Natural Resource Partners Annual Report 2022

Plain-text annual report

Natural Resource Partners L.P.ANNUAL REPORT2022 63615natD1R2_Cov.indd 163615natD1R2_Cov.indd 14/17/23 5:18 PM4/17/23 5:18 PM2022 Accomplishments Generated $268 million of free cash flow, a record for the Partnership Paid $34 million of common unitholder distributions, an increase of 52% from the previous year Permanently retired $269 million of debt Executed first two subsurface carbon dioxide (CO2) sequestration leases with the potential to store up to 800 million metric tons of CO2 Reduced leverage ratio to 0.5x as of December 31, 2022 Closed new five-year, $130 million revolving credit facility 63615natD1R2_Cov.indd 2 63615natD1R2_Cov.indd 2 4/17/23 5:18 PM 4/17/23 5:18 PM Natural Resource Partners L.P. 2022 Annual Report To The Unitholders of Natural Resource Partners L.P. (“NRP”): We are honored by the trust you have placed in us with your investment in NRP. As your partner, we strive to maximize the intrinsic value of your business. We believe that as your partner, our economic interests should be aligned with yours. Every member of your executive team has a meaningful portion of their net worth invested in NRP. Collectively, your executives and Board of Directors own more than 28% of our outstanding common units. Rest assured that our investment goals are closely aligned with yours. We think long-term. We do not provide quarterly guidance or concern ourselves with meeting short-term earnings expectations. Our focus is on maximizing the Partnership’s earning power over five, ten, fifteen years and beyond. We believe this is the best approach to maximizing the intrinsic value of our business, which should in turn, maximize the long-term return on your investment. We believe shared values make for good partnerships. We want partners who invest in us because they share our business philosophy and long-term focus. What We Own NRP owns approximately 13 million acres of mineral interests and other property rights across the United States, including 3.5 million acres of underground pore space for the sequestration of carbon dioxide (“CO2”). If combined in a single tract, our ownership would cover roughly 20,000 square miles. Our assets provide critical inputs for the manufacturing of steel, electricity, building materials and components used in the generation of renewable energy. We also own a 49% interest in Sisecam Wyoming, LLC, one of the world’s lowest cost producers of soda ash, an essential ingredient for the manufacturing of glass, detergents, solar panels and batteries for electric vehicles. What We Do Not Do We do not conduct “operations” on any of our assets or directly engage in any type of industrial activity. Instead, we lease our mineral and other rights to companies that conduct operations on our properties in exchange for paying royalties and other fees to us. Operating expenses, capital costs and other liabilities arising out of production activities are borne entirely by our lessees. In the case of our soda ash investment, operations are managed by our partner, Sisecam Resources, LLC. Our Strategy 2015 marked a watershed event in the history of the Partnership. Falling commodity prices and high debt levels pushed our financial capacity to the brink. We had almost $1.5 billion of debt, representing more than two-thirds of our capital structure. Our bonds were trading at 65 cents on the dollar, and our free cash flow was negative. We could no longer rely on external sources to refinance maturing debt. In response, we embarked on a strategy to de-lever and de-risk the Partnership. Since then, through the extraordinary contributions of our employees and support of external stakeholders, we have made significant strides to improve the Partnership’s financial position and operating performance. We aggressively cut costs, eliminated capital expenditures, and sold off underperforming assets. 63615natD1R2_Narr.indd 1 63615natD1R2_Narr.indd 1 1 4/18/23 5:52 PM 4/18/23 5:52 PM Today, we are proud to say that the Partnership is dramatically healthier and financially stronger than it was seven years ago. We have right-sized the business from four business segments down to two, both of which now earn returns on capital well in excess of their cost of capital. Our operating and interest expenses are each more than 70% lower than they were when we began. Our free cash flow, which had been negative, exceeded a quarter of a billion dollars in 2022, a record for the Partnership. Our debt, which had been almost $1.5 billion, had declined more than 80%, to $169 million at year end. The financial profile of today’s NRP is so remarkedly improved from that of seven years ago, that it would be hardly recognizable to anyone who had not followed the transformation. We are especially proud that these results have been achieved without the use of debt forgiveness or bankruptcy. Let it be known that NRP keeps its promises, pays its debts, and does exactly what it says it will do. We have come a long way, but there is still more work to be done. Our goal remains to retire all permanent debt, redeem all of our 12% convertible preferred equity, and eliminate all outstanding warrants. Business Highlights NRP generated $268 million of free cash flow in 2022, the highest level in the history of the Partnership. We paid off $269 million of debt during the year and our leverage ratio was 0.5x at the end of 2022. We paid out $34 million of common unitholder distributions, which was a 52% increase over the previous year. We have now paid common distributions in every quarter in the Partnership’s history except for one quarter during the depths of uncertainty in the COVID-19 pandemic. We also made noteworthy progress in our efforts to position the Partnership as a key beneficiary of the transitional energy economy with the execution of our first two subsurface CO2 sequestration leases with Denbury Resources and Occidental Petroleum. These projects, which will utilize only 140,000 of the 3.5 million acres of CO2 sequestration rights we own, have the combined potential to permanently store up to 800 million metric tons of CO2. We also executed our first geothermal lease which has the potential to generate up to 15 MW of clean, green energy. Lastly, a holder of our 12% convertible preferred equity elected to convert $47.5 million of preferred units in February of this year. We have the option of settling preferred unit conversions by either paying cash or issuing common units. After considering our financial position, liquidity, and comparing the market value of NRP common units to our estimate of intrinsic value, we decided it would be wise to settle this conversion with the payment of $47.5 million of cash rather than by issuing NRP common units. Conclusion As demonstrated by our continued ability to generate free cash flow, retire permanent debt and pay common distributions, while positioning the Partnership for the transitional energy economy, we remain confident we have the right strategy in place to maximize unitholder value. Thank you to our stakeholders for your continuing support and a special word of appreciation to our Board of Directors for its wise guidance and counsel. Corbin J. Robertson, Jr. Chairman and Chief Executive Officer Craig Nunez President and Chief Operating Officer 2 63615natD1R2_Narr.indd 2 63615natD1R2_Narr.indd 2 4/18/23 5:52 PM 4/18/23 5:52 PM Table of ContentsUNITED STATES SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 10-K ☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2022 or ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number: 001-31465 NATURAL RESOURCE PARTNERS LP (Exact name of registrant as specified in its charter) Delaware35-2164875(State or other jurisdiction ofincorporation or organization)(I.R.S. EmployerIdentification No.)1415 Louisiana Street, Suite 3325Houston, Texas 77002(Address of principal executive offices)(Zip Code)(713) 751-7507(Registrant’s telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of each class Trading Symbol(s) Name of each exchange on which registeredCommon Units representing limited partner interests NRP New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during thepreceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90days. Yes ☒ No ☐Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T(§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growthcompany. See definition of "accelerated filer", "large accelerated filer", "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the ExchangeAct.Large Accelerated Filer☐ Accelerated Filer☒Non-accelerated Filer☐ Smaller Reporting Company☒ Emerging Growth Company☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revisedfinancial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control overfinancial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report ☒If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect thecorrection of an error to previously issued financial statements. ☐Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any ofthe registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act) Yes ☐ No ☒The aggregate market value of the common units held by non-affiliates of the registrant on June 30, 2022, was $334 million based on a closing price on that date of$37.23 per unit as reported on the New York Stock Exchange.Documents incorporated by reference: None. Table of ContentsTABLE OF CONTENTSCautionary Statement Regarding Forward-Looking StatementsiiRisk Factors SummaryiiPART IItems 1. and 2.Business and Properties1Item 1A.Risk Factors15Item 1B.Unresolved Staff Comments26Item 3.Legal Proceedings26Item 4.Mine Safety Disclosures26PART IIItem 5.Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities27Item 6.[RESERVED]27Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations27Item 7A.Quantitative and Qualitative Disclosures About Market Risk39Item 8.Financial Statements and Supplementary Data40Item 9.Changes In and Disagreements with Accountants on Accounting and Financial Disclosure72Item 9A.Controls and Procedures72Item 9B.Other Information74PART IIIItem 10.Directors and Executive Officers of the Managing General Partner and Corporate Governance75Item 11.Executive Compensation80Item 12.Security Ownership of Certain Beneficial Owners and Management83Item 13.Certain Relationships and Related Transactions, and Director Independence85Item 14.Principal Accountant Fees and Services90PART IVItem 15.Exhibits, Financial Statement Schedules92Signatures96iTable of Contents CAUTIONARY STATEMENTREGARDING FORWARD-LOOKING STATEMENTS Statements included in this 10-K may constitute forward-looking statements. In addition, we and our representatives may from time to time make other oral orwritten statements which are also forward-looking statements. Such forward-looking statements include, among other things, statements regarding: the effects of theglobal COVID-19 pandemic; future distributions on our common and preferred units; our business strategy; our liquidity and access to capital and financing sources;our financial strategy; prices of and demand for coal, trona and soda ash, and other natural resources; estimated revenues, expenses and results of operations; projectedproduction levels by our lessees; Sisecam Wyoming LLC’s ("Sisecam Wyoming's"), formerly known as Ciner Wyoming, trona mining and soda ash refinery operations;distributions from our soda ash joint venture; the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us, and ofscheduled or potential regulatory or legal changes; and global and U.S. economic conditions. These forward-looking statements speak only as of the date hereof and are made based upon our current plans, expectations, estimates, assumptions and beliefsconcerning future events impacting us and involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actualresults could differ materially from those expressed or implied in the forward-looking statements. You should not put undue reliance on any forward-looking statements.See "Item 1A. Risk Factors" in this Annual Report on Form 10-K for important factors that could cause our actual results of operations or our actual financial conditionto differ. RISK FACTORS SUMMARY We are subject to a variety of risks and uncertainties, including risks related to our business, risks related to our indebtedness, risks related to our common stockand certain general risks, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Risks that we deemmaterial are described under “Risk Factors” in Item 1A of this report. These risks include, but are not limited to, the following: Risks Related to Our Business •Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of financial reserves. In addition, our debt agreements and ourpartnership agreement place restrictions on our ability to pay, and in some cases raise, the quarterly distribution under certain circumstances.•Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects.•The ongoing COVID-19 pandemic has adversely affected our business, and the ultimate effect on our financial condition, results of operations, and ability to makecash distributions to unitholders will depend on future developments, which are highly uncertain and cannot be predicted.•Prices for both metallurgical and thermal coal are volatile and depend on a number of factors beyond our control. Declines in prices could have a material adverseeffect on our business and results of operations.•Prices for soda ash are volatile. Any substantial or extended decline in soda ash prices could have an adverse effect on Sisecam Wyoming’s ability to continue tomake distributions to us.•We derive a large percentage of our revenues and other income from a small number of coal lessees.•Bankruptcies in the coal industry, and/or the idling or closure of mines on our properties could have a material adverse effect on our business and results ofoperations.•Mining operations are subject to operating risks that could result in lower revenues to us.•The adoption of climate change legislation and regulations restricting emissions of greenhouse gases and other hazardous air pollutants have resulted in changesin fuel consumption patterns by electric power generators and a corresponding decrease in coal production by our lessees and reduced coal-related revenues.•Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are also resulting in unfavorable lending andinvestment policies by institutions and insurance companies which could significantly affect our ability to raise capital or maintain current insurance levels.•Increased attention to climate change, environmental, social and governance (ESG) matters and conservation measures may adversely impact our business.•In addition to climate change and other Clean Air Act legislation, our businesses are subject to numerous other federal, state and local laws and regulations thatmay limit production from our properties and our profitability.•If our lessees do not manage their operations well, their production volumes and our royalty revenues could decrease.•We have limited approval rights with respect to the management of our Sisecam Wyoming soda ash joint venture, including with respect to cash distributions andcapital expenditures. In addition, we are exposed to operating risks that we do not experience in the royalty business through our soda ash joint venture andthrough our ownership of certain coal transportation assets.•Sisecam Wyoming’s deca stockpiles will substantially deplete by 2024, and its production rates will decline approximately 200,000 short tons per year if SisecamWyoming does not make further investments or otherwise execute on one or more initiatives to prevent such decline.•Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal, soda ash and other minerals from ourproperties.•Our lessees could satisfy obligations to their customers with minerals from properties other than ours, depriving us of the ability to receive amounts in excess ofminimum royalty payments.•A lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection process or, if identified, might beidentified in a subsequent period. Table of Contents Risks Related to Our Structure •Unitholders may not be able to remove our general partner even if they wish to do so.•The preferred units are senior in right of distributions and liquidation and upon conversion, would result in the issuance of additional common units in the future,which could result in substantial dilution of our common unitholders’ ownership interests.•We may issue additional common units or preferred units without common unitholder approval, which would dilute a unitholder’s existing ownership interests.•Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.•Cost reimbursements due to our general partner may be substantial and will reduce our cash available for distribution to unitholders.•Conflicts of interest could arise among our general partner and us or the unitholders.•The control of our general partner may be transferred to a third party without unitholder consent. A change of control may result in defaults under certain of ourdebt instruments and the triggering of payment obligations under compensation arrangements.•Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business. Tax Risks to Common Unitholders •Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes as well as our not being subject to a material amount of entity-leveltaxation by individual states. If the Internal Revenue Service ("IRS") were to treat us as a corporation for U.S. federal income tax purposes or we were to becomesubject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantiallyreduced.•The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes ordiffering interpretations, possibly applied on a retroactive basis.•Certain U.S. federal income tax preferences currently available with respect to coal exploration and development may be eliminated as a result of future legislation.•Our unitholders are required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us. Our unitholders' share ofour portfolio income may be taxable to them even though they receive other losses from our activities.•We may engage in transactions to reduce our indebtedness and manage our liquidity that generate taxable income (including income and gain from the sale ofproperties and cancellation of indebtedness income) allocable to our unitholders, and income tax liabilities arising therefrom may exceed any distributions made withrespect to their units.•If the IRS contests the U.S. federal income tax positions we take, the market for our units may be adversely impacted and the cost of any IRS contest will reduce ourcash available for distribution to our unitholders.•If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes(including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to ourunitholders might be substantially reduced.•Tax gain or loss on the disposition of our common units could be more or less than expected.•Our unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.•Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.•Non-U.S. unitholders will be subject to U.S. federal income taxes and withholding with respect to their income and gain from owning our units.•We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge thistreatment, which could adversely affect the value of the common units.•We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge thesemethodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.•We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon theownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge thistreatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.•A unitholder whose units are the subject of a securities loan (e.g., a loan to a "short seller" to cover a short sale of units) may be considered as having disposed ofthose units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and mayrecognize gain or loss from the disposition.•As a result of investing in our units, our unitholders are likely subject to state and local taxes and return filing requirements in jurisdictions where we operate or ownor acquire property. General Risks •Our business is subject to cybersecurity risks. Additional risks and uncertainties not presently known to us or that we currently deem immaterial also may have an adverse effect on our business, financialcondition, results of operations, and cash flows. ivTable of Contents PART I As used in this Part I, unless the context otherwise requires: "we," "our," "us" and the "Partnership" refer to Natural Resource Partners L.P. and, where the contextrequires, our subsidiaries. References to "NRP" and "Natural Resource Partners" refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC or any ofNatural Resource Partners L.P.’s subsidiaries. References to "Opco" refer to NRP (Operating) LLC, a wholly owned subsidiary of NRP, and its subsidiaries. NRP FinanceCorporation ("NRP Finance") is a wholly owned subsidiary of NRP and was a co-issuer with NRP on the 9.125% senior notes due 2025 (the "2025 Senior Notes"). ITEMS 1. AND 2. BUSINESS AND PROPERTIES Partnership Structure and Management We are a publicly traded Delaware limited partnership formed in 2002. We own, manage and lease a diversified portfolio of mineral properties in the United States,including interests in coal and other natural resources and own a non-controlling 49% interest in Sisecam Wyoming LLC ("Sisecam Wyoming"), a trona ore mining andsoda ash production business. Our business is organized into two operating segments: Mineral Rights—consists of approximately 13 million acres of mineral interests and other subsurface rights across the United States. If combined in a single tract,our ownership would cover roughly 20,000 square miles. Our ownership provides critical inputs for the manufacturing of steel, electricity and basic building materials, aswell as opportunities for carbon sequestration and renewable energy. We are working to strategically redefine our business as a key player in the transitional energyeconomy in the years to come. Soda Ash—consists of our 49% non-controlling equity interest in Sisecam Wyoming, a trona ore mining and soda ash production business located in the GreenRiver Basin of Wyoming. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into the glass and chemicalsindustries. Our operations are conducted through Opco and our operating assets are owned by our subsidiaries. NRP (GP) LP, our general partner, has sole responsibility forconducting our business and for managing our operations. Because our general partner is a limited partnership, its general partner, GP Natural Resource Partners LLC,conducts its business and operations and the Board of Directors and officers of GP Natural Resource Partners LLC make decisions on our behalf. Robertson CoalManagement LLC, a limited liability company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC.Subject to the Board Representation and Observation Rights Agreement with certain entities controlled by funds affiliated with Blackstone Inc. (collectively referred toas "Blackstone") and affiliates of GoldenTree Asset Management LP (collectively referred to as "GoldenTree"), Mr. Robertson, Jr. is entitled to appoint the members ofthe Board of Directors of GP Natural Resource Partners LLC and has delegated the right to appoint one director to Blackstone. The senior executives and other officers who manage NRP are employees of Western Pocahontas Properties Limited Partnership or Quintana Minerals Corporation,which are companies controlled by Mr. Robertson, Jr. These officers allocate varying percentages of their time to managing our operations. Neither our general partner,GP Natural Resource Partners LLC, nor any of their affiliates receive any management fee or other compensation in connection with the management of our business, butthey are entitled to be reimbursed for all direct and indirect expenses incurred on our behalf. We have regional offices through which we conduct our operations, the largest of which is located at 5260 Irwin Road, Huntington, West Virginia 25705 and thetelephone number is (304) 522-5757. Our principal executive office is located at 1415 Louisiana Street, Suite 3325, Houston, Texas 77002 and our telephone number is(713) 751-7507. 1Table of Contents Segment and Geographic Information The amount of 2022 revenues and other income from our two operating segments is shown below. For additional business segment information, please see "Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations" and "Item 8. Financial Statements andSupplementary Data—Note 7. Segment Information" in this Annual Report on Form 10-K, which are both incorporated herein by reference. (In thousands) Amount % of Total Mineral Rights $329,167 85%Soda Ash 59,795 15%Total $388,962 100% The following map shows the approximate geographic distribution of our ownership footprint: Table of Contents Mineral Rights Segment Mineral Rights We do not mine, drill or produce minerals. Instead, we lease our acreage to companies engaged in the extraction of minerals in exchange for the payment ofroyalties and various other fees. The royalties we receive are generally a percentage of the gross revenue received by our lessees. The royalties we receive are typicallysupported by a floor price and minimum payment obligation that protect us during significant price or demand declines. The majority of our Mineral Rights segment revenues come from royalties related to the sale of coal from our properties. Our coal is primarily located in theAppalachia Basin, the Illinois Basin and the Northern Powder River Basin in the United States. We lease our coal to experienced mine operators under long-term leases.Approximately two-thirds of our royalty-based leases have initial terms of five to 40 years, with substantially all lessees having the option to extend the lease foradditional terms. Leases include the right to renegotiate royalties and minimum payments for the additional terms. We also own and manage coal-related transportationand processing assets in the Illinois Basin that generate additional revenues generally based on throughput or rents. We also own oil and gas, industrial minerals andaggregates that generate a portion of the Mineral Rights segment revenues. Additional Mineral Rights segment revenues come from carbon neutral initiatives such thesale of carbon offset credits from our forestlands, potential sub-surface carbon dioxide sequestration in our pore space and opportunities to generate geothermal energyfrom our ownership. Under our standard royalty lease, we grant the operators the right to mine and sell our minerals in exchange for royalty payments based on the greater of apercentage of the sale price or fixed royalty per ton of minerals mined and sold. Lessees calculate royalty payments due to us and are required to report tons of mineralsmined and sold as well as the sales prices of the extracted minerals. Therefore, to a great extent, amounts reported as royalty revenues are based upon the reports of ourlessees. We periodically audit this information by examining certain records and internal reports of our lessees and we perform periodic mine inspections to verify thatthe information that our lessees have submitted to us is accurate. Our audit and inspection processes are designed to identify material variances from lease terms as wellas differences between the information reported to us and the actual results from each property. In addition to their royalty obligations, our lessees are often subject to minimum payments, which reflect amounts we are entitled to receive even if no miningactivity occurs during the period. Minimum payments are usually credited against future royalties that are earned as minerals are produced. In certain leases, the lesseeis time limited on the period available for recouping minimum payments and such time is unlimited on other leases. Because we do not operate, our royalty business does not bear ordinary operating costs and has limited direct exposure to environmental, permitting and laborrisks. Our lessees, as operators, are subject to environmental laws, permitting requirements and other regulations adopted by various governmental authorities. Inaddition, the lessees generally bear all labor-related risks, including retiree health care costs, black lung benefits and workers’ compensation costs associated withoperating the mines on our coal and aggregates properties. We pay property taxes on our properties, which are largely reimbursed by our lessees pursuant to the termsof the various lease agreements. The SEC amended the property disclosure requirements for registrants with significant mining activities, effective for the fiscal year 2021, with new rules which wecomply with in this Annual Report on Form 10-K. The rules contain exceptions that allow royalty companies, such as NRP, to omit information that they lack access toand cannot obtain without incurring an unreasonable burden or expense. As a royalty company, we do not have access to the information required to prepare thetechnical reports used to determine reserves under the rules, and we are not able to obtain such information without unreasonable burden or expense. The rules requirethat reserve estimates be based on and disclosures include technical reports prepared using extensive mine-specific geological and engineering data, as well as marketand cost assumptions that we as a mineral owner do not have, including, but not limited to a) site infrastructure costs; b) processing plant costs; c) detailed analysis ofenvironmental compliance and permitting requirements; d) detailed baseline studies with impact assessment; and e) detailed tailings disposal, reclamation and mitigationplans. Our leases do not require the operators of our material properties to prepare technical report summaries or permit us the access and information sufficient toprepare our own technical report summaries under the rules. As a result, we are relying on the royalty company exceptions and have ceased to report coal and otherhard mineral reserves. In addition to summary information about our overall portfolio of mineral rights, this section provides detailed information about four properties in our MineralRights segment. These properties were determined to be material to our business based on historical revenue compared to our Mineral Rights segment considered as awhole. These four properties are: 1) Alpha-CAPP (VA), 2) Oak Grove, 3) Williamson, and 4) Hillsboro. We have also included a description of other significant properties,which have had lower revenues historically than our material properties but are important to our business. Coal Metallurgical Coal Metallurgical (“Met”) coal is used to fuel blast furnaces that forge steel and is the primary driver of our long-term cash flows. Met coal is a high-quality, cleanercoal that generates exceptionally high temperatures when burned and is an essential element in the steel manufacturing process. Metallurgical coal is a finite anddeclining resource, particularly in industrialized nations. We believe the indispensable role met coal plays in manufacturing steel combined with the increasing scarcityof the resource will provide support for this portion of our business for decades to come. Our metallurgical coal is located in the Northern, Central and SouthernAppalachian regions of the United States. Thermal Coal Thermal coal, sometimes referred to as steam coal, is used in the production of electricity. The amount of thermal coal produced in the United States has beensteadily falling over the last decade as energy providers shift from coal-fired plants to natural gas-fired facilities, and to a lesser extent, alternative energy sources suchas geothermal, wind and solar. We believe the long-term secular decline experienced by thermal coal over the last decade will continue. That fact, combined with thelong-term strength of our metallurgical business and the carbon neutral initiatives we discuss below, will result in thermal coal becoming a diminishing contributor toNRP in years to come. The vast majority of our thermal sales are located in Illinois and its operations are some of the most cost-efficient mines east of the MississippiRiver. The remainder of our thermal coal is located in Montana, the Gulf Coast and Appalachia. 2Table of Contents Coal Production Information The following tables present the type of coal sales volumes by major coal region for the years ended December 31, 2022, 2021 and 2020: For the Year Ended December 31, 2022 Type of Coal (Tons in thousands) Thermal Metallurgical Total Appalachia Basin Northern 1,166 530 1,696 Central 1,186 12,460 13,646 Southern 93 1,691 1,784 Total Appalachia Basin 2,445 14,681 17,126 Illinois Basin 11,135 — 11,135 Northern Powder River Basin 4,288 — 4,288 Gulf Coast 385 — 385 Total 18,253 14,681 32,934 For the Year Ended December 31, 2021 Type of Coal (Tons in thousands) Thermal Metallurgical Total Appalachia Basin Northern 718 617 1,335 Central 1,140 11,139 12,279 Southern 119 1,452 1,571 Total Appalachia Basin 1,977 13,208 15,185 Illinois Basin 9,388 — 9,388 Northern Powder River Basin 3,151 — 3,151 Gulf Coast 55 — 55 Total 14,571 13,208 27,779 For the Year Ended December 31, 2020 Type of Coal (Tons in thousands) Thermal Metallurgical Total Appalachia Basin Northern 267 380 647 Central 1,157 8,954 10,111 Southern 143 746 889 Total Appalachia Basin 1,567 10,080 11,647 Illinois Basin 3,381 — 3,381 Northern Powder River Basin 1,738 — 1,738 Total 6,686 10,080 16,766 Major Coal Producing Properties The following table provides a summary of our significant coal royalty properties for 2022 and is followed by additional information for each property: Region Property/Lease Name Operator(s) Coal TypeAppalachia Basin Northern Carter Roag Metinvest MetCentral Alpha-CAPP (VA) Alpha Metallurgical Resources Inc. MetCentral Kepler Alpha Metallurgical Resources Inc. MetCentral Elk Creek Ramaco Royalty Company, LLC MetCentral Coal Mountain ECP MetSouthern Oak Grove Hatfield Metallurgical Coal Holdings, LLC MetIllinois Basin Williamson Foresight Energy Resources LLC ThermalIllinois Basin Hillsboro Foresight Energy Resources LLC ThermalNorthern Powder River Basin Western Energy Rosebud Mining, LLC Thermal 3Table of Contents Appalachia Basin—Northern Appalachia Carter Roag. The Carter Roag property is located in Randolph and Upshur counties, West Virginia. Substantially all of the tons sold from this property in 2022were metallurgical coal. We lease this property to subsidiaries of Metinvest. Production comes from underground room and pillar mines, is processed onsite at the StarBridge Prep Plant, and is sold primarily on the export market. Appalachia Basin—Central Appalachia Alpha-CAPP (VA). The Alpha-CAPP (VA) property is located in Wise, Dickenson, Russell and Buchanan Counties, Virginia. Substantially all of the tons soldfrom this property in 2022 were metallurgical coal. We lease this property to subsidiaries of Alpha Metallurgical Resources Inc. ("Alpha") and previously leased it tosubsidiaries of Contura Energy, Inc. The current lease with Alpha expires at the end of 2023 and will automatically renew unless otherwise notified. We receive paymentsbased on the greater of a percentage of the sale price or fixed royalty per ton of coal mined and sold. In addition to the royalty obligations, this lease is subject tominimum payments, which reflect amounts we are entitled to receive even if no mining activity occurs during the period. Minimum payments are credited against futureroyalties that are earned as minerals are produced and the lessee is time limited on the period available for recouping minimum payments. Production comes fromunderground room and pillar and surface mines and is trucked to one of two preparation plants. Coal is shipped via the CSX and Norfolk Southern railroads to utility andmetallurgical customers. The book value of this property was $47.2 million at December 31, 2022. Below is a map of our Alpha-CAPP (VA) property: Elk Creek. The Elk Creek property is located in Logan and Wyoming Counties, West Virginia. We lease this property to Ramaco Resources, Inc. Metallurgicalcoal is produced from surface and underground mines and is transported by belt and truck to a preparation plant on the property. Coal is shipped via the CSX railroad toboth domestic and export metallurgical customers. Coal Mountain. The Coal Mountain property is located in Wyoming County, West Virginia. We lease this property to ECP. Metallurgical coal is produced from amulti-seam surface mine and coal is transported by truck to a preparation plant on the property. Coal is shipped via the Norfolk Southern railroad to both domestic andexport metallurgical customers. Kepler. The Kepler property is located in Wyoming County, West Virginia. Substantially all of the coal sold from this property in 2022 were metallurgical coal. Welease this property to a subsidiary of Alpha. Coal is produced from underground mines and transported by belt or truck to the preparation plant on the property. Coal isshipped via the Norfolk Southern railroad to export metallurgical customers. 4Table of Contents Appalachia Basin—Southern Appalachia Oak Grove. The Oak Grove property is located in Jefferson County, Alabama. We currently lease this property to a subsidiary of Hatfield Metallurgical CoalHoldings, LLC ("Hatfield Metallurgical"). Previous operators of this property were Murray Metallurgical Coal Holdings LLC, Mission Coal, LLC, and Seneca Resources,LLC. The current lease with Hatfield Metallurgical expires in 2024 and will automatically renew unless otherwise notified. We receive payments based on the greater of apercentage of the sale price or fixed royalty per ton of coal mined and sold. In addition to the royalty obligations, this lease is subject to minimum payments, whichreflect amounts we are entitled to receive even if no mining activity occurs during the period. Minimum payments are credited against future royalties that are earned asminerals are produced and the lessee is time limited on the period available for recouping minimum payments. Metallurgical coal production comes from a longwall mineand is transported by beltline to a preparation plant. Metallurgical products are then shipped via railroad and barge to both domestic and export customers. The bookvalue of this property was $4.6 million at December 31, 2022. Below is a map of our Oak Grove property: 5Table of Contents Illinois Basin Williamson. The Williamson property is located in Franklin and Williamson Counties, Illinois. This property is under leases to Williamson Energy, a subsidiary ofForesight Energy Resources LLC ("Foresight"). The current leases expire in 2026 and 2033 and will automatically renew unless otherwise notified. We receive paymentsbased on the greater of a percentage of the sale price or fixed royalty per ton of coal mined and sold. In addition to the royalty obligations, these leases are subject tominimum payments, which reflect amounts we are entitled to receive even if no mining activity occurs during the period. Minimum payments are credited against futureroyalties that are earned as minerals are produced and the lessee is time limited on the period available for recouping minimum payments. Thermal coal production comesfrom a longwall mine. Coal is shipped primarily via the Canadian National railroad to export customers. The book value of this property was $40.2 million at December 31,2022. Below is a map of our Williamson property: 6Table of Contents Hillsboro. The Hillsboro property is located in Montgomery and Bond Counties, Illinois. This property is under lease to Hillsboro Energy, a subsidiary ofForesight. The current lease expires in 2033 and will automatically renew unless otherwise notified. We receive payments based on the greater of a percentage of the saleprice or fixed royalty per ton of coal mined and sold. In addition to the royalty obligations, this lease is subject to non-recoupable minimum payments, which reflectamounts we are entitled to receive even if no mining activity occurs during the period. Thermal coal production comes from a longwall mine. Coal is shipped by rail viaeither the Union Pacific, Norfolk Southern or Canadian National railroads, or by barges to domestic utilities customers. The book value of this property was $215.8million at December 31, 2022. Below is a map of our Hillsboro property: In addition to these properties, we own loadout and other transportation assets at the Williamson mine and at the Macoupin and Sugar Camp mines, which are alsooperated by Foresight. See "—Coal Transportation and Processing Assets" below for additional information on these assets. Production at the Foresight Macoupin mine was temporarily ceased in March 2020. Foresight is no longer obligated to make royalty, transportation fee, orquarterly minimum payments to us under the Macoupin coal mining lease and transportation agreements. Foresight will pay an annual Macoupin fee of $2.0 million toNRP each year through 2023. Foresight also forfeited its right to recoup all previously paid but unrecouped minimum payments with respect to the Macoupin mine. At alltimes that the Macoupin mine remains in temporary cessation of production, Foresight will take reasonable actions to preserve, protect, and store the equipment,infrastructure, and property located at the mine. Beginning January 1, 2024, we may at any time elect to cause Foresight to transfer the Macoupin mine and all associated equipment and permits to us for noconsideration. If we make this election, we will assume all liabilities associated with the Macoupin mine. Also beginning January 1, 2024, Foresight may at any time electto offer to sell the Macoupin assets to us for $1.00. If we accept Foresight’s offer, we will assume all liabilities associated with the Macoupin mine. If we do not acceptForesight’s offer, Foresight may proceed to permanently seal the Macoupin mine and conduct all reclamation activities. To the extent the elections described above arenot made, Foresight will continue to pay the annual $2.0 million fee to NRP each year that the mine remains in temporary cessation of production. In addition, Foresightmay determine at any time to recommence operations at the Macoupin mine, at which time we and Foresight will negotiate in good faith to enter into new coal mininglease and transportation agreements. 7Table of Contents Northern Powder River Basin Western Energy. The Western Energy property is located in Rosebud and Treasure Counties, Montana. We lease this property to a subsidiary of RosebudMining, LLC. Thermal coal is produced by surface dragline mining methods. Coal is transported by either truck or beltline to the Colstrip generation station located atthe mine mouth. Coal Transportation and Processing Assets We own transportation and processing infrastructure related to certain of our coal properties, including loadout and other transportation assets at Foresight'sWilliamson mine in the Illinois Basin, for which we collect throughput fees or rents. We lease our Williamson transportation and processing infrastructure to a subsidiaryof Foresight and are responsible for operating and maintaining the transportation and processing assets at the Williamson mine that we subcontract to a subsidiary ofForesight. In addition, we own rail loadout and associated infrastructure at the Sugar Camp mine, an Illinois Basin mine also operated by a subsidiary of Foresight.While we own coal at the Williamson mine, we do not own coal at the Sugar Camp mine. The infrastructure at the Sugar Camp mine is leased to a subsidiary of Foresightand we collect minimums and throughput fees. We recorded $21.1 million in revenue related to our coal transportation and processing assets during the year endedDecember 31, 2022. We also own transportation and processing infrastructure, including loadout and other transportation assets at Foresight's Macoupin mine. As previouslymentioned, the Macoupin mine was temporarily ceased in March 2020 and Foresight is no longer obligated to make transportation fee payments to us under thetransportation agreements. Oil and Gas / Industrial Minerals / Construction Aggregates / Timber Our oil and gas properties are predominately located in Louisiana. Our various industrial mineral and construction aggregates properties are located across theUnited States and include minerals such as limestone, frac sand, lithium, copper, lead and zinc. We lease a portion of these minerals to third parties in exchange forroyalty payments. The structure of these leases is similar to our coal leases, and these leases typically require minimum rental payments in addition to royalties. During2022, we received $3.3 million in aggregates royalty revenues, including overriding royalty revenues. We also own forest assets, primarily in West Virginia, whichgenerate revenues from the forestland through carbon offset credits and timber sales. Carbon Neutral Initiatives We continue to identify alternative revenue sources across our large portfolio of land and mineral assets. The types of opportunities include the sequestration ofcarbon dioxide ("CO2") underground and in standing forests, and the generation of electricity using geothermal, solar and wind energy. As with our existing mineralactivities, we do not plan to develop or operate carbon sequestration or carbon neutral energy projects ourselves but we plan to lease our acreage to companies that willconduct those operations in exchange for payment of royalties and other fees to us. While the timing and likelihood of additional cash flows being realized from theseactivities is uncertain, we believe our large ownership footprint throughout the United States will provide additional opportunities to create value in this regard andposition us as a key beneficiary of the transitional energy economy with minimal capital investment. We executed our first carbon neutral project in the fourth quarter of 2021 through the sale of 1.1 million carbon offset credits for $13.8 million. The offset creditswere issued to us by the California Air Resources Board under its cap-and-trade program and represent 1.1 million metric tons of carbon sequestered in approximately39,000 acres of our forestland in West Virginia. Carbon Sequestration. We own approximately 3.5 million acres of specifically reserved subsurface rights in the southern United States with the potential forpermanent sequestration of greenhouse gases. The carbon capture utilization and storage industry (“CCUS”) is in its infancy and the future is highly uncertain, but afew facts are clear. A sequestration project requires acreage possessing unique geologic characteristics, close proximity to sources of industrial-scale greenhouse gasemissions, and the appropriate form of legal title that grants the acreage owner the right to sequester emissions in the subsurface. While carbon sequestration rights andownership continue to evolve, we believe we own one of the largest inventory of acreage with potential for carbon sequestration activities in the United States. In the first quarter of 2022 we executed our first subsurface CO2 sequestration lease on 75,000 acres of underground pore space we own in southwest Alabamawith the potential to store over 300 million metric tons of CO2. In October of 2022, we announced our second subsurface CO2 transaction with the execution of a leasefor approximately 65,000 acres of pore space we control near southeast Texas with estimated storage capacity of at least 500 million metric tons of CO2. In total, we haveapproximately 140,000 acres of pore space under lease for carbon sequestration with estimated CO2 storage capacity of 800 million metric tons. Renewable Energy. In addition, we believe portions of our asset base across the United States possess the geologic characteristics and geographical locationsnecessary for geothermal, solar and wind energy development. With regards to geothermal, the technology to generate safe and reliable “green” electricity using heatfound deep underground is advancing rapidly. Once limited to the geologic “hot spots,” new technology has made geothermal energy projects feasible in many placespreviously thought impossible. Our geothermal opportunities are predominately located in the South, Midwest and Northwest parts of the United States. In the thirdquarter of 2022 we executed our first geothermal lease with the potential to generate up to 15 megawatts of electricity. With regards to wind and solar energyopportunities, we are actively engaged in discussions for potential use of our acreage for these types of renewable energy developments predominantly in Kentuckyand West Virginia. 8Table of Contents Soda Ash Segment We own a 49% non-controlling equity interest in Sisecam Wyoming. Sisecam Resources LP, our operating partner ("Sisecam Resources"), controls and operatesSisecam Wyoming. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into the glass and chemicalsindustries. Sisecam Resources is a publicly traded master limited partnership that depends on distributions from Sisecam Wyoming in order to make distributions to itspublic unitholders. As a minority interest owner in Sisecam Wyoming, we do not operate and are not involved in the day-to-day operation of the trona ore mine or sodaash production plant. We appoint three of the seven members of the Board of Managers of Sisecam Wyoming and have certain limited negative controls relating to thecompany. We have limited approval rights with respect to Sisecam Wyoming, and our partner controls most business decisions, including decisions with respect todistributions and capital expenditures. In December 2021, Sisecam Resources, the owner of the remaining 51% of our soda ash business was subject to a change in control. Prior to the transaction,Sisecam Wyoming was referred to as Ciner Wyoming and Sisecam Resources was referred to as Ciner Resources L.P. Upon closing of the transaction, Ciner EnterprisesInc., the indirect owner of approximately 74% of the partnership units of Ciner Resources L.P., sold 60% of its interest in Ciner Resources Corporation, the parentcompany of Ciner Resources L.P., to Sisecam Chemicals USA Inc. (“Sisecam USA”), an indirect subsidiary of Türkiye Şişe ve Cam Fabrikalari A.Ş. Ciner ResourcesCorporation subsequently changed its name to Sisecam Chemical Resources LLC and Ciner Resources L.P. changed its name to Sisecam Resources L.P. Following thetransaction, we continue to have the right to appoint three of the seven Board of Managers of Sisecam Wyoming. Sisecam USA has the right to direct the appointmentof four members of the Sisecam Wyoming Board of Managers that are allocated to Sisecam Resources. Sisecam Wyoming is one of the largest and lowest cost producers of soda ash in the world, serving a global market from its facility located in the Green River Basinof Wyoming. The Green River Basin geological formation holds the largest, and one of the highest purity, known deposits of trona ore in the world. Trona, a naturallyoccurring soft mineral, is also known as sodium sesquicarbonate and consists primarily of sodium carbonate, or soda ash, sodium bicarbonate and water. SisecamWyoming processes trona ore into soda ash, which is an essential raw material in flat glass, container glass, detergents, chemicals, paper and other consumer andindustrial products. The vast majority of the world’s accessible trona is located in the Green River Basin. According to historical production statistics, approximately30% of global soda ash is produced by processing trona, with the remainder being produced synthetically through chemical processes. The costs associated withprocuring the materials needed for synthetic production are greater than the costs associated with mining trona for trona-based production. In addition, trona-basedproduction consumes less energy and produces fewer undesirable by-products than synthetic production. Sisecam Wyoming’s Green River Basin surface operations are situated on approximately 2,360 acres in Wyoming (of which, 880 acres are owned by SisecamWyoming), and its mining operations consist of approximately 24,000 acres of leased and licensed subsurface mining area. The facility is accessible by both road andrail. Sisecam Wyoming uses seven large continuous mining machines and 14 underground shuttle cars in its mining operations. Its processing assets consist primarilyof material sizing units, conveyors, calciners, dissolver circuits, thickener tanks, drum filters, evaporators and rotary dryers. In trona ore processing, insoluble materials and other impurities are removed by thickening and filtering liquor, a solution consisting of sodium carbonatedissolved in water. Sisecam Wyoming then adds activated carbon to filters to remove organic impurities, which can cause color contamination in the final product. Theresulting clear liquid is then crystallized in evaporators, producing sodium carbonate monohydrate. The crystals are then drawn off and passed through a centrifuge toremove excess water. The resulting material is dried in a product dryer to form anhydrous sodium carbonate, or soda ash. The resulting processed soda ash is thenstored in on-site storage silos to await shipment by bulk rail or truck to distributors and end customers. Sisecam Wyoming’s storage silos can hold over 58,900 shorttons of processed soda ash at any given time. The facility is in good working condition and has been in service for more than 60 years. Deca Rehydration. The evaporation stage of trona ore processing produces a precipitate and natural by-product called deca. "Deca," short for sodium carbonatedecahydrate, is one part soda ash and ten parts water. Solar evaporation causes deca to crystallize and precipitate to the bottom of the four main surface ponds at theGreen River Basin facility. The deca rehydration process enables Sisecam Wyoming to recover soda ash from the deca-rich purged liquor as a by-product of the refiningprocess. The soda ash contained in deca is captured by allowing the deca crystals to evaporate in the sun and separating the dehydrated crystals from the soda ash.The separated deca crystals are then blended with partially processed trona ore in the dissolving stage of the production process. This process enables SisecamWyoming to reduce waste storage needs and convert what is typically a waste product into a usable raw material. Sisecam Wyoming anticipates that its current decastockpiles will be exhausted by 2024 and that production rates will decline approximately 200,000 short tons per year if that production capacity is not replaced. Shipping and Logistics. For the year ended December 31, 2022, Sisecam Wyoming assisted the majority of its domestic customers in arranging their freightservices. All of the soda ash produced is shipped by rail or truck from the Green River Basin facility. For the year ended December 31, 2022, Sisecam Wyoming shippedover 90% of its soda ash to its customers initially via a single rail line owned and controlled by Union Pacific Railroad Company ("Union Pacific"). The SisecamWyoming plant receives rail service exclusively from Union Pacific. The agreement with Union Pacific expires on December 31, 2025 and there can be no assurance that itwill be renewed on terms favorable to Sisecam Wyoming or at all. If Sisecam Wyoming does not ship at least a significant portion of its soda ash production on theUnion Pacific rail line during a twelve-month period, they must pay Union Pacific a shortfall payment under the terms of its transportation agreement. During 2022,Sisecam Wyoming had no shortfall payments and does not expect to make any such payments in the future. A leased fleet of more than 2,200 hopper cars serve asdedicated modes of shipment to Sisecam Wyoming's domestic and international customers. For exports, soda ash is shipped on unit trains primarily out of Longview,Washington for bulk shipments. Sisecam Wyoming has contracts securing its export capacity in bulk vessels and containers vessels. From these ports, soda ash isloaded onto ships for delivery to ports all over the world. Sisecam Wyoming ships to customers on Cost and Freight ("CFR") and Cost, Insurance, and Freight ("CIF")basis where they pay for ocean freight and charge the customer directly for these freight costs. Sisecam Wyoming has yearly and multiyear contracts for a portion of itsocean freight with vessel owners and carriers securing capacity and reducing market risk fluctuation. 9Table of Contents Customers. Sisecam Wyoming generated approximately half of its gross revenue from export sales, which consist of both customers as well as distributors whoserve as its channel partners in certain markets. The two largest customers in its portfolio are distributors in its export network who, on a combined basis, make up26% of its total gross revenue. For customers in North America, Sisecam Chemical Resources LLC ("Sisecam Chemical Resources") typically enters into contracts on Sisecam Wyoming’s behalfwith terms ranging from one to three years. Sisecam Chemical Resources is the parent company of the sole member of the general partner of our operating partner,Sisecam Resources. Sisecam Chemical Resources is owned 60% by Sisecam USA and 40% by Ciner Enterprises Inc. Under these contracts, customers generally agree topurchase either minimum estimated volumes of soda ash or a certain percentage of their soda ash requirements at a fixed price for a given calendar year. AlthoughSisecam Wyoming does not have “take or pay” arrangements with its customers, substantially all sales are made pursuant to written agreements and not through spotsales. In 2022, Sisecam Wyoming had more than 80 domestic customers and has had long-term relationships with the majority of its customers. Sisecam Wyoming’s customers consist primarily of glass manufacturing companies, which account for 50% or more of the consumption of soda ash around theworld, and chemical and detergent manufacturing companies. Sisecam Chemicals has now completed two full years directly managing its international sales, marketing and logistics activities since exiting ANSAC at the end of2020. Sisecam Chemicals took direct control of these activities to improve access to customers and gain control over placement of its sales in the internationalmarketplace. This enhanced view of the global market allows Sisecam chemicals to better understand supply/demand fundamentals thus allowing better decision makingfor its business. Sisecam Chemicals continues to optimize its distribution network leveraging strengths of existing distribution partners while expanding as its businessrequires in certain target areas. Leases and License. Sisecam Wyoming is party to several mining leases and one license for its subsurface mining rights. Some of the leases are renewable atSisecam Wyoming’s option upon expiration. Sisecam Wyoming pays royalties to the State of Wyoming, the U.S. Bureau of Land Management and Sweetwater RoyaltiesLLC, a subsidiary of Sweetwater Trona OpCo LLC and the successor in interest to the license with the Rock Springs Royalty Company LLC, an affiliate of OccidentalPetroleum Corporation (formerly an affiliate of Anadarko Petroleum Corporation). The royalties are calculated based upon a percentage of the value of soda ash andrelated products sold at a certain stage in the mining process. These royalty payments may be subject to a minimum domestic production volume from the Green RiverBasin facility. Sisecam Wyoming is also obligated to pay annual rentals to its lessors and licensor regardless of actual sales. In addition, Sisecam Wyoming pays aproduction tax to Sweetwater County, and trona severance tax to the State of Wyoming that is calculated based on a formula that utilizes the volume of trona ore minedand the value of the soda ash produced. Sisecam Wyoming has a perpetual right to continue operating under these leases and license as long as it maintains continuousmining operations and intends to continue renewing the leases and license as has been historical practice. Expansion Project. Sisecam Wyoming announced a significant capacity expansion capital project in 2019 that could increase production levels to up to 3.5 milliontons of soda ash per year. Basic design work and cost analysis were completed and necessary permits were obtained. However, in light of significant cost inflation,Sisecam Wyoming has decided not to proceed with the project at this time. Sisecam Wyoming continues to remain focused on evaluating capacity expansionopportunities. As a minority interest owner in Sisecam Wyoming, we do not operate and are not involved in the day-to-day operation of the trona ore mine or soda ashproduction plant. Our partner, Sisecam Resources, manages the mining and plant operations. We appoint three of the seven members of the Board of Managers ofSisecam Wyoming and have certain limited negative controls relating to the company. Significant Customers We have a significant concentration of revenues from Alpha, with total revenues of $102.4 million in 2022 from several different mining operations, includingwheelage revenues. We also have a significant concentration of revenues with Foresight and its subsidiaries, with total revenues of $65.6 million in 2022 from all of theirmining operations, including transportation and processing services revenues, coal overriding royalty revenues and wheelage revenues. For additional information onsignificant customers, refer to "Item 8. Financial Statements and Supplementary Data—Note 14. Major Customers." Competition We face competition from land companies, coal producers, international steel companies and private equity firms in purchasing coal and royalty producingproperties. Numerous producers in the coal industry make coal marketing intensely competitive. Our lessees compete among themselves and with coal producers invarious regions of the United States for domestic sales. Lessees compete with both large and small producers nationwide on the basis of coal price at the mine, coalquality, transportation cost from the mine to the customer and the reliability of supply. Continued demand for our coal and the prices that our lessees obtain are alsoaffected by demand for electricity and steel, as well as government regulations, technological developments and the availability and the cost of generating power fromalternative fuel sources, including nuclear, natural gas, wind, solar and hydroelectric power. Sisecam Wyoming's trona mining and soda ash refinery business faces competition from a number of soda ash producers in the United States, Europe and Asia,some of which have greater market share and greater financial, production and other resources than Sisecam Wyoming does. Some of Sisecam Wyoming’s competitorsare diversified global corporations that have many lines of business and some have greater capital resources and may be in a better position to withstand a long-termdeterioration in the soda ash market. Other competitors, even if smaller in size, may have greater experience and stronger relationships in their local markets. Competitivepressures could make it more difficult for Sisecam Wyoming to retain its existing customers and attract new customers, and could also intensify the negative impact offactors that decrease demand for soda ash in the markets it serves, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental orregulatory actions that directly or indirectly increase the cost or limit the use of soda ash. 10Table of Contents Title to Property We owned substantially all of our coal and aggregates mineral rights in fee as of December 31, 2022. We lease the remainder from unaffiliated third parties. SisecamWyoming leases or licenses its trona. We believe that we have satisfactory title to all of our mineral properties, but we have not had a qualified title company confirmthis belief. Although title to these properties is subject to encumbrances in certain cases, such as customary easements, rights-of-way, interests generally retained inconnection with the acquisition of real property, licenses, prior reservations, leases, liens, restrictions and other encumbrances, we believe that none of these burdenswill materially detract from the value of our properties or from our interest in them or will materially interfere with their use in the operation of our business. For most of our properties, the surface, oil and gas and mineral or coal estates are not owned by the same entities. Some of those entities are our affiliates. Statelaw and regulations in most of the states where we do business require the oil and gas owner to coordinate the location of wells so as to minimize the impact on theintervening coal seams. We do not anticipate that the existence of the severed estates will materially impede development of the minerals on our properties. Regulation and Environmental Matters General Operations on our properties must be conducted in compliance with all applicable federal, state and local laws and regulations. These laws and regulations includematters involving the discharge of materials into the environment, employee health and safety, mine permits and other licensing requirements, reclamation andrestoration of mining properties after mining is completed, management of materials generated by mining operations, surface subsidence from underground mining,water pollution, legislatively mandated benefits for current and retired coal miners, air quality standards, protection of wetlands, plant and wildlife protection, limitationson land use, storage of petroleum products and substances which are regarded as hazardous under applicable laws and management of electrical equipment containingpolychlorinated biphenyls ("PCBs"). Because of extensive, comprehensive and often ambiguous regulatory requirements, violations during natural resource extractionoperations are not unusual and, notwithstanding compliance efforts, we do not believe violations can be eliminated entirely. While it is not possible to quantify the costs of compliance with all applicable federal, state and local laws and regulations, those costs have been and are expectedto continue to be significant. Our lessees in our coal and aggregates royalty businesses are required to post performance bonds pursuant to federal and state mininglaws and regulations for the estimated costs of reclamation and mine closures, including the cost of treating mine water discharge when necessary. In many states ourlessees also pay taxes into reclamation funds that states use to achieve reclamation where site specific performance bonds are inadequate to do so. Determinations byfederal or state agencies that site specific bonds or state reclamation funds are inadequate could result in increased bonding costs for our lessees or even a cessation ofoperations if adequate levels of bonding cannot be maintained. We do not accrue for reclamation costs because our lessees are both contractually liable and liable underthe permits they hold for all costs relating to their mining operations, including the costs of reclamation and mine closures. Although the lessees typically accrueadequate amounts for these costs, their future operating results would be adversely affected if they later determined these accruals to be insufficient. In recent years,compliance with these laws and regulations has substantially increased the cost of coal mining for all domestic coal producers. In addition, the electric utility industry, which is the most significant end-user of thermal coal, is subject to extensive regulation regarding the environmental impactof its power generation activities, which has affected and is expected to continue to affect demand for coal mined from our properties. Current and future proposedlegislation and regulations could be adopted that will have a significant additional impact on the mining operations of our lessees or their customers’ ability to use coaland may require our lessees or their customers to change operations significantly or incur additional substantial costs that would negatively impact the coal industry. Many of the statutes discussed below also apply to Sisecam Wyoming’s trona mining and soda ash production operations, and therefore we do not present aseparate discussion of statutes related to those activities, except where appropriate. Air Emissions The Clean Air Act and corresponding state and local laws and regulations affect all aspects of our business. The Clean Air Act directly impacts our lessees’ coalmining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources thatemit various hazardous and non-hazardous air pollutants. The Clean Air Act also indirectly affects coal mining operations by extensively regulating the air emissions ofcoal-fired electric power generating plants. There have been a series of federal rulemakings that are focused on emissions from coal-fired electric generating facilities,including the Cross-State Air Pollution Rule ("CSAPR"), regulating emissions of nitrogen oxide ("NOx") and sulfur dioxide, and the Mercury and Air Toxics Rule("MATS"), regulating emissions of hazardous air pollutants. In March 2021, the U.S. Environmental Protection Agency ("EPA") revised the CSAPR to require additionalemissions reductions of NOx from power plants in twelve states. Further, in April 2022, EPA published a proposed rule to build on the CSAPR by imposing FederalImplementation Plans on over 20 states to implement the 2015 National Ambient Air Quality Standards (NAAQS) for ozone. Installation of additional emissions controltechnologies and other measures required under EPA regulations make it more costly to operate coal-fired power plants and could make coal a less attractive or eveneffectively prohibited fuel source in the planning, building and operation of power plants in the future. These rules and regulations have resulted in a reduction in coal’sshare of power generating capacity, which has negatively impacted our lessees’ ability to sell coal and our coal-related revenues. Further reductions in coal’s share ofpower generating capacity as a result of compliance with existing or proposed rules and regulations would have a material adverse effect on our coal-related revenues. 11Table of Contents Carbon Dioxide and Greenhouse Gas ("GHG") Emissions In December 2009, EPA determined that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and welfare becauseemissions of such gases are, according to EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on its findings, EPA beganadopting and implementing regulations to restrict emissions of GHGs under various provisions of the Clean Air Act. In August 2015, EPA published its final Clean Power Plan ("CPP") Rule, a multi-factor plan designed to cut carbon pollution from existing power plants, includingcoal-fired power plants. The rule required improving the heat rate of existing coal-fired power plants and substituting lower carbon-emission sources like natural gas andrenewables in place of coal. As promulgated, the rule would force many existing coal-fired power plants to incur substantial costs in order to comply or alternativelyresult in the closure of some of these plants, likely resulting in a material adverse effect on the demand for coal by electric power generators. The rule was beingchallenged by several states, industry participants and other parties in the United States Court of Appeals for the District of Columbia Circuit. In February 2016, theSupreme Court of the United States stayed the CPP Rule pending a decision by the District of Columbia Circuit as well as any subsequent review by the Supreme Court.In April 2017, the United States Court of Appeals for the District of Columbia Circuit granted EPA’s motion to hold the litigation in abeyance. In December 2017, EPAissued a proposed rule repealing the CPP Rule and issued an Advance Notice of Proposed Rulemaking soliciting information regarding a potential replacement rule tothe CPP Rule. In August 2018, EPA formally proposed the Affordable Clean Energy ("ACE") Rule, which would replace the CPP Rule. The ACE Rule contemplates anarrower approach than the CPP Rule, focusing on efficiency improvements at existing power plants and eliminating the CPP Rule’s broader goals that envisionedswitches to non-fossil fuel energy sources and the implementation of efficiency measures on demand-side entities, which the EPA now considers beyond the reach of itsauthority under the Clean Air Act. The ACE Rule would also omit specific numerical emissions targets that had been established under the CPP Rule. The ACE Rulewent into effect on September 6, 2019. As a result, the United States Court of Appeals for the District of Columbia Circuit dismissed the pending challenges to the CPPRule as moot. The ACE Rule was challenged by public health groups, environmental groups, states, municipalities, industry groups, and power providers. The legalchallenges were consolidated as American Lung Assoc. v. EPA before the D.C. Circuit Court of Appeals. Dozens of parties and over 170 amici filed briefs on the merits,and oral argument was held before a three-judge panel in October 2020. In January 2021, the D.C. Circuit issued a written opinion holding that the ACE Rule was basedon EPA’s “erroneous legal premise” that when it determines the “best system of emission reduction” for existing sources, the Clean Air Act mandates that EPA may onlyconsider emission reduction measures that can be applied at and/or to a stationary source (often referred to as “inside-the-fence” measures). The Court vacated the rule,essentially reimplementing the CPP and leaving EPA to decide whether to stick with the CPP or to pursue a new rulemaking. In June 2022, the Supreme Court issued awritten opinion, West Virginia v. EPA, in which the Court invalidated the CPP because EPA lacked the authority to promulgate such an expansive rule under the “MajorQuestions Doctrine.” It is unclear whether the Biden administration will issue a replacement of the CPP. In October 2015, EPA published its final rule on performance standards for greenhouse gas emissions from new, modified, and reconstructed electric generatingunits. The final rule requires new steam generating units to use highly efficient supercritical pulverized coal boilers that use partial post-combustion carbon capture andstorage technology. The final emission standard is less stringent than EPA had originally proposed due to updated cost assumptions, but could still have a materialadverse effect on new coal-fired power plants. The final rule has been challenged by several states, industry participants and other parties in the United States Court ofAppeals for the District of Columbia Circuit, but is not subject to a stay. In April 2017, the court granted EPA’s motion to hold the litigation in abeyance while EPAreviews the rule. In December 2018, EPA issued a proposed rule revising the best system of emission reduction (“BSER”) for newly constructed coal-fired electricgenerating units, among other changes, to replace the 2015 rule. In a status report filed with the Court on January 15, 2021, EPA requested that the case remain inabeyance until after the transition to the Biden administration. On March 17, 2021, in line with President Biden’s Executive Order 13990, EPA asked the D.C. Circuit tovacate and remand the “significant contribution” final rule. On April 5, 2021, the D.C. Circuit vacated and remanded the January 2021 final rule. President Obama also announced an emission reduction agreement with China’s President Xi Jinping in November 2014. The United States pledged that by 2025 itwould cut climate pollution by 26% to 28% from 2005 levels. China pledged it would reach its peak carbon dioxide emissions around 2030 or earlier, and increase its non-fossil fuel share of energy to around 20% by 2030. In December 2015, the United States was one of 196 countries that participated in the Paris Climate Conference, atwhich the participants agreed to limit their emissions in order to limit global warming to 2°C above pre-industrial levels, with an aspirational goal of 1.5°C. While there isno way to estimate the impact of these climate pledges and agreements, they could ultimately have an adverse effect on the demand for coal, both nationally andinternationally, if implemented. In 2019, President Trump withdrew from the Paris Climate Agreement. On February 19, 2021, the United States officially rejoined the ParisClimate Agreement per President Biden’s order signed January 20. Hazardous Materials and Waste The Federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or the Superfund law) and analogous state laws imposeliability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered responsible for having contributed to the releaseof a “hazardous substance” into the environment. We could become liable under federal and state Superfund and waste management statutes if our lessees are unableto pay environmental cleanup costs relating to hazardous substances. In addition, we may have liability for environmental clean-up costs in connection with SisecamWyoming's soda ash businesses. 12Table of Contents Water Discharges Operations conducted on our properties can result in discharges of pollutants into waters. The Clean Water Act and analogous state laws and regulations createtwo permitting programs for mining operations. The National Pollutant Discharge Elimination System (NPDES) program under Section 402 of the statute is administeredby the states or EPA and regulates the concentrations of pollutants in discharges of waste and storm water from a mine site. The Section 404 program is administered bythe Army Corps of Engineers and regulates the placement of overburden and fill material into channels, streams and wetlands that comprise “waters of the UnitedStates.” The scope of waters that may fall within the jurisdictional reach of the Clean Water Act is expansive and may include land features not commonly understood tobe a stream or wetlands. The Clean Water Act and its regulations prohibit the unpermitted discharge of pollutants into such waters, including those from a spill or leak.Similarly, Section 404 also prohibits discharges of fill material and certain other activities in waters unless authorized by the issued permit. In June 2015, EPA issued anew rule defining the scope of “Waters of the United States” (WOTUS) that are subject to regulation. The 2015 WOTUS rule was challenged by a number of states andprivate parties in federal district and circuit courts. In December 2017, EPA and the Corps proposed a rule to repeal the 2015 WOTUS rule and implement the pre-2015definition. The repeal of the 2015 WOTUS rule took effect in December 2019. In December 2018, EPA and the Corps issued a proposed rule again revising the definitionof “Waters of the United States.” The new rule (the Navigable Waters Protection Rule) took effect in June 2020. In most of the pending legal challenges to the 2015WOTUS rule, the petitioners filed amended complaints to include allegations challenging the 2020 rule. In addition, various industry groups, environmental groups, andstates filed new legal challenges to the 2020 rule. In August 2021, the U.S. District Court for the District of Arizona vacated and remanded the 2020 rule. In light of thisorder, agencies have reverted to interpreting WOTUS in line with the pre-2015 regulatory regime. In late November 2021, EPA proposed a rule to revise the definition yetagain, this time to restore the pre-2015 definition, with updates to reflect recent Supreme Court decisions. In connection with its review of permits, EPA has at times sought to reduce the size of fills and to impose limits on specific conductance (conductivity) and sulfateat levels that can be unachievable absent treatment at many mines. Such actions by EPA could make it more difficult or expensive to obtain or comply with such permits,which could, in turn, have an adverse effect on our coal-related revenues. In addition to government action, private citizens’ groups have continued to be active in bringing lawsuits against operators and landowners. Since 2012, severalcitizen group lawsuits have been filed against mine operators for allegedly violating conditions in their National Pollutant Discharge Elimination System (“NPDES”)permits requiring compliance with West Virginia’s water quality standards. Some of the lawsuits alleged violations of water quality standards for selenium, whereasothers alleged that discharges of conductivity and sulfate were causing violations of West Virginia’s narrative water quality standards, which generally prohibit adverseeffects to aquatic life. The citizen suit groups have sought penalties as well as injunctive relief that would limit future discharges of selenium, conductivity or sulfate.The federal district court for the Southern District of West Virginia has ruled in favor of the citizen suit groups in multiple suits alleging violations of the water qualitystandard for selenium and in two suits alleging violations of water quality standards due to discharges of conductivity (one of which was upheld on appeal by theUnited States Court of Appeals for the Fourth Circuit in January 2017). Additional rulings requiring operators to reduce their discharges of selenium, conductivity orsulfate could result in large treatment expenses for our lessees. In 2015, the West Virginia Legislature enacted certain changes to West Virginia’s NPDES program toexpressly prohibit the direct enforcement of water quality standards against permit holders. EPA approved those changes as a program revision effective in March 2019.This approval may prevent future citizen suits alleging violations of water quality standards. Since 2013, several citizen group lawsuits have been filed against landowners alleging ongoing discharges of pollutants, including selenium and conductivity, fromvalley fills located at reclaimed mountaintop removal mining sites in West Virginia. In each case, the mine on the subject property has been closed, the property has beenreclaimed, and the state reclamation bond has been released. Any determination that a landowner or lessee has liability for discharges from a previously reclaimed minesite could result in substantial compliance costs or fines and would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations. 13Table of Contents Other Regulations Affecting the Mining Industry Mine Health and Safety Laws The operations of our coal lessees and Sisecam Wyoming are subject to stringent health and safety standards that have been imposed by federal legislation sincethe adoption of the Mine Health and Safety Act of 1969. The Mine Health and Safety Act of 1969 resulted in increased operating costs and reduced productivity. TheMine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Health and Safety Act of 1969, imposescomprehensive health and safety standards on all mining operations. In addition, the Black Lung Acts require payments of benefits by all businesses conductingcurrent mining operations to coal miners with black lung or pneumoconiosis and to some beneficiaries of miners who have died from this disease. Mining accidents in recent years have received national attention and instigated responses at the state and national level that have resulted in increased scrutinyof current safety practices and procedures at all mining operations, particularly underground mining operations. Since 2006, heightened scrutiny has been applied to thesafe operations of both underground and surface mines. This increased level of review has resulted in an increase in the civil penalties that mine operators have beenassessed for non-compliance. Operating companies and their supervisory employees have also been subject to criminal convictions. The Mine Safety and HealthAdministration ("MSHA") has also advised mine operators that it will be more aggressive in placing mines in the Pattern of Violations program, if a mine’s rate of injuriesor significant and substantial citations exceed a certain threshold. A mine that is placed in a Pattern of Violations program will receive additional scrutiny from MSHA. Surface Mining Control and Reclamation Act of 1977 The Surface Mining Control and Reclamation Act of 1977 ("SMCRA") and similar statutes enacted and enforced by the states impose on mine operators theresponsibility of reclaiming the land and compensating the landowner for types of damages occurring as a result of mining operations. To ensure compliance with anyreclamation obligations, mine operators are required to post performance bonds. Our coal lessees are contractually obligated under the terms of our leases to complywith all federal, state and local laws, including SMCRA. Upon completion of the mining, reclamation generally is completed by seeding with grasses or planting trees foruse as pasture or timberland, as specified in the reclamation plan approved by the state regulatory authority. In addition, higher and better uses of the reclaimedproperty are encouraged. Mining Permits and Approvals Numerous governmental permits or approvals such as those required by SMCRA and the Clean Water Act are required for mining operations. In connection withobtaining these permits and approvals, our lessees may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact thatany proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and maydelay commencement or continuation of mining operations. In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including our lessees, must submit a reclamation plan forreclaiming the mined property upon the completion of mining operations. Our lessees have obtained or applied for permits to mine a majority of the coal that is currentlyplanned to be mined over the next five years. Our lessees are also in the planning phase for obtaining permits for the additional coal planned to be mined over thefollowing five years. However, given the imposition of new requirements in the permits in the form of policies and the increased oversight review that has been exercisedby EPA, there are no assurances that they will not experience difficulty and delays in obtaining mining permits in the future. In addition, EPA has used its authority tocreate significant delays in the issuance of new permits and the modification of existing permits, which has led to substantial delays and increased costs for coaloperators. Employees and Labor Relations As of December 31, 2022, affiliates of our general partner employed 54 people who directly supported our operations. None of these employees were subject to acollective bargaining agreement. Website Access to Partnership Reports Our Internet address is www.nrplp.com. We make available free of charge on or through our Internet website our Annual Report on Form 10-K, Quarterly Reportson Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. Information on our website isnot a part of this report. In addition, the SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other informationfiled by us. Corporate Governance Matters Our Code of Business Conduct and Ethics, our Disclosure Controls and Procedures Policy and our Corporate Governance Guidelines adopted by our Board ofDirectors, as well as the charter for our Audit Committee are available on our website at www.nrplp.com. Copies of our annual report, our Code of Business Conduct andEthics, our Disclosure Controls and Procedures Policy, our Corporate Governance Guidelines and our committee charters will be made available upon written request toour principal executive office at 1415 Louisiana St., Suite 3325, Houston, Texas 77002. 14Table of Contents ITEM 1A. RISK FACTORS Risks Related to Our Business Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of financial reserves. In addition, our debt agreements andour partnership agreement place restrictions on our ability to pay, and in some cases raise, the quarterly distribution under certain circumstances. Because distributions on the common units are dependent on the amount of cash we generate, distributions fluctuate based on our performance. The actualamount of cash that is available to be distributed each quarter depends on numerous factors, some of which are beyond our control and the control of the generalpartner. Cash distributions are dependent primarily on cash flow, and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions mightbe made during periods when we record losses and might not be made during periods when we record profits. The actual amount of cash we have to distribute eachquarter is reduced by payments in respect of debt service and other contractual obligations, including distributions on the preferred units, fixed charges, maintenancecapital expenditures, and reserves for future operating or capital needs that the board of directors may determine are appropriate. We have significant debt serviceobligations and obligations to pay cash distributions on our preferred units. To the extent our board of directors deems appropriate, it may determine to decrease theamount of the quarterly distribution on our common units or suspend or eliminate the distribution on our common units altogether. In addition, because our unitholdersare required to pay income taxes on their respective shares of our taxable income, our unitholders may be required to pay taxes in excess of any future distributions wemake. Our unitholders' share of our portfolio income may be taxable to them even though they receive other losses from our activities. See "—Tax Risks to OurUnitholders—Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us. Our unitholders' share ofour portfolio income may be taxable to them even though they receive other losses from our activities." Our partnership agreement requires our consolidated leverage ratio to be less than 3.25x in order to make quarterly distributions on the common units in an amountin excess of $0.45 per unit. For more information on restrictions on our ability to make distributions on our common units, see "Item 7. Management’s Discussion and Analysis of FinancialCondition and Results of Operations—Liquidity and Capital Resources" and "Item 8. Financial Statements and Supplementary Data—Note 11. Debt, Net." Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects. As of December 31, 2022, we and our subsidiaries had approximately $169.1 million of total indebtedness. The terms and conditions governing the indenture forOpco’s revolving credit facility and senior notes:•require us to meet certain leverage and interest coverage ratios;•require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance ouroperations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industries in which we operate;•increase our vulnerability to economic downturns and adverse developments in our business;•limit our ability to access the bank and capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures oracquisitions or to refinance existing indebtedness;•place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;•place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governingtheir indebtedness;•make it more difficult for us to satisfy our obligations under our debt agreements and increase the risk that we may default on our debt obligations; and•limit management’s discretion in operating our business. Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatoryand other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cashflow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations, including payment of distributions on the preferred units.If we do not have sufficient funds, we may be required to refinance all or part of our existing debt, borrow more money, or sell assets or raise equity at unattractiveprices, including higher interest rates. We are required to make substantial principal repayments each year in connection with Opco’s senior notes, with approximately$40 million due thereunder during 2023. To the extent we borrow to make some of these payments, we may not be able to refinance these amounts on terms acceptable tous, if at all. We may not be able to refinance our debt, sell assets, borrow more money or access the bank and capital markets on terms acceptable to us, if at all. Ourability to comply with the financial and other restrictive covenants in our debt agreements will be affected by the levels of cash flow from our operations and futureevents and circumstances beyond our control. Failure to comply with these covenants would result in an event of default under our indebtedness, and such an event ofdefault could adversely affect our business, financial condition and results of operations. 15Table of Contents The ongoing COVID-19 pandemic has adversely affected our business, and the ultimate effect on our financial condition, results of operations, and ability to makecash distributions to unitholders will depend on future developments, which are highly uncertain and cannot be predicted. The COVID-19 pandemic adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. Inaddition, the pandemic resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities andglobal trading markets. Coal markets faced substantial challenges prior to the pandemic, and widespread increases in unemployment and decreases in electricity andsteel demand further reduced demand and prices for coal in 2020. In addition, demand for and prices of soda ash decreased in 2020, as global manufacturing slowed. Ourboard of directors determined to suspend cash distributions to our common unitholders with respect to the first quarter of 2020 in order to preserve liquidity due touncertainties created by the pandemic. In addition, Sisecam Wyoming suspended cash distributions to its members in 2020 due to adverse effects of the pandemic onthe global and domestic soda ash markets. Both companies have resumed distributions, however there remains a risk that distributions could be suspended in the futuredue to a resumption of pandemic uncertainties. As economic activity began to recover throughout 2021 and 2022, so did supply and demand for coal and soda ash. While the outbreak appeared to be trendingdownward, particularly as vaccination rates increased, new variants of COVID-19 emerged, including the highly transmissible Delta and Omicron variants, spreadingthroughout the United States and globally and causing significant uncertainty. The full extent to which the COVID-19 pandemic will impact our results is not fully knownand is evolving, and will depend on future developments, which are highly uncertain and cannot be predicted. These include the severity, duration and spread ofCOVID-19, the success of actions taken by governments and health organizations to combat the disease and treat its effects, including additional remedial legislation,the emergence of any new COVID-19 variants that may arise, the timing, availability, effectiveness and adoption rates of vaccines and treatments and the extent towhich, and when, general economic and operating conditions recover. Accordingly, any resulting financial impact cannot be reasonably estimated at this time but suchamounts may be material. To the extent our board of directors deems necessary, it may determine to suspend cash distributions in future quarters as a result of thepandemic. Prices for both metallurgical and thermal coal are volatile and depend on a number of factors beyond our control. Declines in prices could have a material adverseeffect on our business and results of operations. Coal prices continue to be volatile and prices could decline substantially from current levels. Production by some of our lessees may not be economic if pricesdecline further or remain at current levels. The prices our lessees receive for their coal depend upon factors beyond their or our control, including:•the supply of and demand for domestic and foreign coal;•domestic and foreign governmental regulations and taxes;•changes in fuel consumption patterns of electric power generators;•the price and availability of alternative fuels, especially natural gas;•global economic conditions, including the strength of the U.S. dollar relative to other currencies;•global and domestic demand for steel;•tariff rates on imports and trade disputes, particularly involving the United States and China;•the availability of, proximity to and capacity of transportation networks and facilities;•global or national health concerns, including the outbreak of pandemic or contagious disease, such as the ongoing COVID-19 pandemic;•weather conditions; and•the effect of worldwide energy conservation measures. Natural gas is the primary fuel that competes with thermal coal for power generation, and renewable energy sources continue to gain market share in powergeneration. The abundance and ready availability of cheap natural gas, together with increased governmental regulations on the power generation industry has causeda number of utilities to switch from thermal coal to natural gas and/or close coal-powered generation plants. This switching has resulted in a decline in thermal coalprices, and to the extent that natural gas prices remain low, thermal coal prices will also remain low. Reduced international demand for export thermal coal and increasedcompetition from global producers has also put downward pressure on thermal coal prices. Our lessees produce a significant amount of metallurgical coal that is used for steel production domestically and internationally. Since the amount of steel that isproduced is tied to global economic conditions, declines in those conditions could result in the decline of steel, coke and metallurgical coal production. Sincemetallurgical coal is priced higher than thermal coal, some mines on our properties may only operate profitably if all or a portion of their production is sold asmetallurgical coal. If these mines are unable to sell metallurgical coal, they may not be economically viable and may be temporarily idled or closed. Any potential futurelessee bankruptcy filings could create additional uncertainty as to the future of operations on our properties and could have a material adverse effect on our businessand results of operations. To the extent our lessees are unable to economically produce coal over the long term, the carrying value of our coal mineral rights could be adversely affected. Along-term asset generally is deemed impaired when the future expected cash flow from its use and disposition is less than its book value. For the year ended December31, 2022, we recorded impairment charges of approximately $4.5 million related to properties that we believe our current or future lessees are unable to operate profitably.Future impairment analyses could result in additional downward adjustments to the carrying value of our assets. 16Table of Contents Prices for soda ash are volatile. Any substantial or extended decline in soda ash prices could have an adverse effect on Sisecam Wyoming’s ability to continue tomake distributions to its members and on our results of operations. The market price of soda ash directly affects the profitability of Sisecam Wyoming’s soda ash production operations. If the market price for soda ash declines,Sisecam Wyoming’s sales will decrease. Historically, the global market and, to a lesser extent, the domestic market for soda ash has been volatile, and those markets arelikely to remain volatile in the future. The prices Sisecam Wyoming receives for its soda ash depend on numerous factors beyond Sisecam Wyoming’s control, includingthe COVID-19 pandemic, worldwide and regional economic and political conditions impacting supply and demand. In addition, the impact of the Sisecam ChemicalResources' exit from ANSAC and Sisecam Wyoming’s transition to the utilization of Sisecam Group’s global distribution network for some of its export operationsbeginning 2021 could affect prices received for export sales. Glass manufacturers and other industrial customers drive most of the demand for soda ash, and thesecustomers experience significant fluctuations in demand and production costs. Competition from increased use of glass substitutes, such as plastic and recycled glass,has had a negative effect on demand for soda ash. Substantial or extended declines in prices for soda ash could have a material adverse effect on Sisecam Wyoming’sability to continue to make distributions to its members and on our results of operations. We derive a large percentage of our revenues and other income from a small number of coal lessees. Challenges in the coal mining industry have led to significant consolidation activity. We own significant interests in several of Alpha's mining operations, whichaccounted for approximately 26% of our total revenues in 2022. We also own significant interests in all of Foresight’s mining operations, which accounted forapproximately 17% of our total revenues in 2022. Certain other lessees have made acquisitions over the past few years resulting in their having an increased interest inour coal. Any interruption in these lessees’ ability to make royalty payments to us could have a disproportionate material adverse effect on our business and results ofoperations. Bankruptcies in the coal industry, and/or the idling or closure of mines on our properties could have a material adverse effect on our business and results ofoperations. While current coal prices have recovered substantially, the recent coal price environment, together with high operating costs and limited access to capital, hascaused a number of coal producers to file for protection under The U.S. Bankruptcy Code and/or idle or close mines that they cannot operate profitably. To the extentour leases are accepted or assigned in a bankruptcy process, pre-petition amounts are required to be cured in full, but we may ultimately make concessions in thefinancial terms of those leases in order for the reorganized company or new lessor to operate profitably going forward. To the extent our leases are rejected, operationson those leases will cease, and we will be unlikely to recover the full amount of our rejection damages claims. More of our lessees may file for bankruptcy in the future,which will create additional uncertainty as to the future of operations on our properties and could have a material adverse effect on our business and results ofoperations. Mining operations are subject to operating risks that could result in lower revenues to us. Our revenues are largely dependent on the level of production of minerals from our properties, and any interruptions to or increases in costs of the productionfrom our properties may reduce our revenues. The level of production and costs thereof are subject to operating conditions or events beyond our or our lessees’ controlincluding:•difficulties or delays in acquiring necessary permits or mining or surface rights;•reclamation costs and bonding costs;•changes or variations in geologic conditions, such as the thickness of the mineral deposits and the amount of rock embedded in or overlying the mineral deposit;•mining and processing equipment failures and unexpected maintenance problems;•the availability of equipment or parts and increased costs related thereto;•the availability of transportation networks and facilities and interruptions due to transportation delays;•adverse weather and natural disasters, such as heavy rains and flooding;•labor-related interruptions and trained personnel shortages; and•mine safety incidents or accidents, including hazardous conditions, roof falls, fires and explosions. While our lessees maintain insurance coverage, there is no assurance that insurance will be available or cover the costs of these risks. Many of our lessees areexperiencing rising costs related to regulatory compliance, insurance coverage, permitting and reclamation bonding, transportation, and labor. Increased costs result indecreased profitability for our lessees and reduce the competitiveness of coal as a fuel source. In addition, we and our lessees may also incur costs and liabilitiesresulting from third-party claims for damages to property or injury to persons arising from their operations. The occurrence of any of these events or conditions couldhave a material adverse effect on our business and results of operations. 17Table of Contents The adoption of climate change legislation and regulations restricting emissions of greenhouse gases and other hazardous air pollutants have resulted in changesin fuel consumption patterns by electric power generators and a corresponding decrease in coal production by our lessees and reduced coal-related revenues. Enactment of laws and passage of regulations regarding emissions from the combustion of coal by the U.S., some of its states or other countries, or other actionsto limit such emissions, have resulted in and could continue to result in electricity generators switching from coal to other fuel sources and in coal-fueled power plantclosures. Further, regulations regarding new coal-fueled power plants could adversely impact the global demand for coal. The potential financial impact on us of existingand future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance oncoal as a fuel source. The amount of coal consumed for domestic electric power generation is affected primarily by the overall demand for electricity, the price andavailability of competing fuels for power plants and environmental and other governmental regulations. We expect that substantially all newly constructed power plantsin the United States will be fired by natural gas because of lower construction and compliance costs compared to coal-fired plants and because natural gas is a cleanerburning fuel. The increasingly stringent requirements of rules and regulations promulgated under the federal Clean Air Act have resulted in more electric powergenerators shifting from coal to natural-gas-fired power plants, or to other alternative energy sources such as solar and wind. These changes have resulted in reducedcoal consumption and the production of coal from our properties and are expected to continue to have an adverse effect on our coal-related revenues. In addition to EPA’s greenhouse gas initiatives, there are several other federal rulemakings that are focused on emissions from coal-fired electric generatingfacilities, including the Cross-State Air Pollution Rule (CSAPR) as revised in 2021, regulating emissions of nitrogen oxide and sulfur dioxide, and the Mercury and AirToxics Rule (MATS), regulating emissions of hazardous air pollutants. Installation of additional emissions control technologies and other measures required under theseand other EPA regulations have made it more costly to operate many coal-fired power plants and have resulted in and are expected to continue to result in plantclosures. Further reductions in coal’s share of power generating capacity as a result of compliance with existing or proposed rules and regulations would have a materialadverse effect on our coal-related revenues. For more information on regulation of greenhouse gas and other air pollutant emissions, see "Items 1. and 2. Business andProperties—Regulation and Environmental Matters.” Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are also resulting in unfavorable lending andinvestment policies by institutions and insurance companies which could significantly affect our ability to raise capital or maintain current insurance levels. Global climate issues continue to attract public and scientific attention. Numerous reports have engendered concern about the impacts of human activity, especiallyfossil fuel combustion, on global climate issues. In addition to government regulation of greenhouse gas and other air pollutant emissions, there have also been effortsin recent years affecting the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups,promoting the divestment of fossil fuel equities and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuels, such as coal. Oneexample is the Net Zero Banking Alliance, a group of over 100 banks worldwide representing over 40% of global banking assets who are committed to aligning theirinvestment portfolios with net zero emissions by 2050. The impact of such efforts may adversely affect our ability to raise capital. In addition, a number of insurancecompanies have taken action to limit coverage for companies in the coal industry, which could result in significant increases in our costs of insurance or in our inabilityto maintain insurance coverage at current levels. Increased attention to climate change, environmental, social and governance (ESG) matters and conservation measures may adversely impact our business. Increasing attention to climate change, societal expectations on companies to address climate change, and investor and societal expectations regarding ESG mattersand disclosures, may result in increased costs, reduced profits, increased investigations and litigation, and negative impacts on our access to capital. Organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies ontheir approach to ESG matters, and many of these ratings processes are inconsistent with each other. Such ratings are used by some investors to inform their investmentand voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increasednegative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock priceand our access to and costs of capital. Furthermore, if our competitors’ ESG performance is perceived to be greater than ours, potential or current investors may elect toinvest in our competitors instead. In addition to climate change and other Clean Air Act legislation, our businesses are subject to numerous other federal, state and local laws and regulations thatmay limit production from our properties and our profitability. The operations of our lessees and Sisecam Wyoming are subject to stringent health and safety standards under increasingly strict federal, state and localenvironmental, health and safety laws, including mine safety regulations and governmental enforcement policies. Failure to comply with these laws and regulations mayresult in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limitor cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our properties. New environmental legislation, new regulations and new interpretations of existing environmental laws, including regulations governing permitting requirements,could further regulate or tax mining industries and may also require significant changes to operations, the incurrence of increased costs or the requirement to obtain newor different permits, any of which could decrease our revenues and have a material adverse effect on our financial condition or results of operations. Under SMCRA, ourcoal lessees have substantial reclamation obligations on properties where mining operations have been completed and are required to post performance bonds for theirreclamation obligations. To the extent an operator is unable to satisfy its reclamation obligations or the performance bonds posted are not sufficient to cover thoseobligations, regulatory authorities or citizens groups could attempt to shift reclamation liability onto the ultimate landowner, which if successful, could have a materialadverse effect on our financial condition. In addition to governmental regulation, private citizens’ groups have continued to be active in bringing lawsuits against coal mine operators and land owners thatallege violations of water quality standards resulting from ongoing discharges of pollutants from reclaimed mining operations, including selenium and conductivity. Anydetermination that a landowner or lessee has liability for discharges from a previously reclaimed mine site would result in uncertainty as to continuing liability forcompleted and reclaimed coal mine operations and could result in substantial compliance costs or fines. 18Table of Contents If our lessees do not manage their operations well, their production volumes and our royalty revenues could decrease. We depend on our lessees to effectively manage their operations on our properties. Our lessees make their own business decisions with respect to their operationswithin the constraints of their leases, including decisions relating to:•the payment of minimum royalties;•marketing of the minerals mined;•mine plans, including the amount to be mined and the method and timing of mining activities;•processing and blending minerals;•expansion plans and capital expenditures;•credit risk of their customers;•permitting;•insurance and surety bonding;•acquisition of surface rights and other mineral estates;•employee wages;•transportation arrangements;•compliance with applicable laws, including environmental laws; and•mine closure and reclamation. A failure on the part of one of our lessees to make royalty payments, including minimum royalty payments, could give us the right to terminate the lease, repossessthe property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement lessee. We might not be able tofind a replacement lessee and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the existinglessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If weenter into a new lease, the replacement operator might not achieve the same levels of production or sell minerals at the same price as the lessee it replaced. In addition, itmay be difficult for us to secure new or replacement lessees. We have limited approval rights with respect to the management of our Sisecam Wyoming soda ash joint venture, including with respect to cash distributions andcapital expenditures. In addition, we are exposed to operating risks that we do not experience in the royalty business through our soda ash joint venture andthrough our ownership of certain coal transportation assets. We do not have control over the operations of Sisecam Wyoming. We have limited approval rights with respect to Sisecam Wyoming, and our partner controlsmost business decisions, including decisions with respect to distributions and capital expenditures. During 2020, Sisecam Wyoming suspended cash distributions to itsmembers due to adverse developments in the soda ash market resulting from the COVID-19 pandemic. Distributions resumed in 2021 but no assurance can be made thatadditional suspensions will not occur in the future. In December 2021, the parent of the 51% owner of Sisecam Wyoming (formerly Ciner Wyoming) sold 60% of itsinterest to Sisecam Chemicals USA Inc., a wholly owned subsidiary of Türkiye Şişe ve Cam Fabrikalari A.Ş. As a result of the transaction, we will continue to appointthree of the seven Board of Managers of Sisecam Wyoming, Sisecam USA will appoint three and Ciner Enterprises Inc. will appoint one. Any changes to the distributionpolicy or the capital expenditure plans approved by the newly constituted Board of Managers could adversely affect the future cash flows to NRP and the financialcondition and results of operations of Sisecam Wyoming. In addition, we are ultimately responsible for operating the transportation infrastructure at Foresight’s Williamson mine, and have assumed the capital andoperating risks associated with that business. As a result of these investments, we could experience increased costs as well as increased liability exposure associatedwith operating these facilities. Sisecam Wyoming’s deca stockpiles will substantially deplete by 2024 and its production rates will decline approximately 200,000 short tons per year if SisecamWyoming does not make further investments or otherwise execute on one or more initiatives to prevent such decline. In 2024, Sisecam Wyoming’s deca stockpiles will be substantially depleted and Sisecam Wyoming's production rates will decline approximately 200,000 short tons(approximately 7% of Sisecam Wyoming production), which would impact Sisecam Wyoming's profitability. While Sisecam Wyoming is currently evaluating whether andwhen to pursue one or more initiatives that could offset this decline as well as provide additional soda ash production above current rates, there is no guarantee thatany such initiatives or investments will be executed successfully, in a timely manner, or if at all to enable Sisecam Wyoming to maintain its current rates of production. 19Table of Contents Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal, soda ash and other minerals from ourproperties. Transportation costs represent a significant portion of the total delivered cost for the customers of our lessees. Increases in transportation costs could make coal aless competitive source of energy or could make minerals produced by some or all of our lessees less competitive than coal produced from other sources. On the otherhand, significant decreases in transportation costs could result in increased competition for our lessees from producers in other parts of the country. Our lessees depend upon railroads, barges, trucks and beltlines to deliver minerals to their customers. Disruption of those transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks and/or other events could temporarily impair the ability of our lessees to supply coal to theircustomers and/or increase their costs. Many of our lessees are currently experiencing transportation-related issues due in particular to decreased availability andreliability of rail services and port congestion. Our lessees’ transportation providers may face difficulties in the future that would impair the ability of our lessees tosupply minerals to their customers, resulting in decreased royalty revenues to us. In addition, Sisecam Wyoming transports its soda ash by rail or truck and ocean vessel. As a result, its business and financial results are sensitive to increases inrail freight, trucking and ocean vessel rates. Increases in transportation costs, including increases resulting from emission control requirements, port taxes andfluctuations in the price of fuel, could make soda ash a less competitive product for glass manufacturers when compared to glass substitutes or recycled glass, or couldmake Sisecam Wyoming’s soda ash less competitive than soda ash produced by competitors that have other means of transportation or are located closer to theircustomers. Sisecam Wyoming may be unable to pass on its freight and other transportation costs in full because market prices for soda ash are generally determined bysupply and demand forces. In addition, rail operations are subject to various risks that may result in a delay or lack of service at Sisecam Wyoming’s facility, andalternative methods of transportation are impracticable or cost prohibitive. For the year ended December 31, 2022, Sisecam Wyoming shipped over 90% of its soda ashfrom the Green River facility on a single rail line owned and controlled by Union Pacific. Any substantial interruption in or increased costs related to the transportationof Sisecam Wyoming’s soda ash or the failure to renew the rail contract on favorable terms could have a material adverse effect on our financial condition and results ofoperations. Our lessees could satisfy obligations to their customers with minerals from properties other than ours, depriving us of the ability to receive amounts in excess ofminimum royalty payments. Mineral supply contracts generally do not require operators to satisfy their obligations to their customers with resources mined from specific locations. Severalfactors may influence a lessee’s decision to supply its customers with minerals mined from properties we do not own or lease, including the royalty rates under thelessee’s lease with us, mining conditions, mine operating costs, cost and availability of transportation, and customer specifications. In addition, lessees move on and offof our properties over the course of any given year in accordance with their mine plans. If a lessee satisfies its obligations to its customers with minerals from propertieswe do not own or lease, production on our properties will decrease, and we will receive lower royalty revenues. A lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection process or, if identified, might beidentified in a subsequent period. We depend on our lessees to correctly report production and royalty revenues on a monthly basis. Our regular lessee audits and mine inspections may notdiscover any irregularities in these reports or, if we do discover errors, we might not identify them in the reporting period in which they occurred. Any undiscoveredreporting errors could result in a loss of royalty revenues and errors identified in subsequent periods could lead to accounting disputes as well as disputes with ourlessees. Risks Related to Our Structure Unitholders may not be able to remove our general partner even if they wish to do so. Our general partner manages and operates NRP. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on mattersaffecting our business. Unitholders have no right to elect the general partner or the directors of the general partner on an annual or any other basis. Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have little practical ability to remove our general partner orotherwise change its management. Our general partner may not be removed except upon the vote of the holders of at least 66 2/3% of our outstanding common units(including common units held by our general partner and its affiliates and including common units deemed to be held by the holders of the preferred units who votealong with the common unitholders on an as-converted basis). Because of their substantial ownership in us, the removal of our general partner would be difficultwithout the consent of both our general partner and its affiliates and the holders of the preferred units. In addition, the following provisions of our partnership agreement may discourage a person or group from attempting to remove our general partner or otherwisechange our management:•generally, if a person (other than the holders of preferred units) acquires 20% or more of any class of units then outstanding other than from our general partner orits affiliates, the units owned by such person cannot be voted on any matter; and•our partnership agreement contains limitations upon the ability of unitholders to call meetings or to acquire information about our operations, as well as otherlimitations upon the unitholders’ ability to influence the manner or direction of management. As a result of these provisions, the price at which the common units will trade may be lower because of the absence or reduction of a takeover premium in thetrading price. 20Table of Contents The preferred units are senior in right of distributions and liquidation and upon conversion, would result in the issuance of additional common units in the future,which could result in substantial dilution of our common unitholders’ ownership interests. The preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. We are required to pay quarterly distributionson the preferred units (plus any PIK units issued in lieu of preferred units) in an amount equal to 12.0% per year prior to paying any distributions on our common units.The preferred units also rank senior to the common units in right of liquidation and will be entitled to receive a liquidation preference in any such case. The preferred units may also be converted into common units under certain circumstances. The number of common units issued in any conversion will be basedon the then-current trading price of the common units at the time of conversion. Accordingly, the lower the trading price of our common units at the time of conversion,the greater the number of common units that will be issued upon conversion of the preferred units, which would result in greater dilution to our existing commonunitholders. Dilution has the following effects on our common unitholders:•an existing unitholder’s proportionate ownership interest in NRP will decrease;•the amount of cash available for distribution on each unit may decrease;•the relative voting strength of each previously outstanding unit may be diminished; and•the market price of the common units may decline. In addition, to the extent the preferred units are converted into more than 66 2/3% of our common units, the holders of the preferred will have the right to removeour general partner. We may issue additional common units or preferred units without common unitholder approval, which would dilute a unitholder’s existing ownership interests. Our general partner may cause us to issue an unlimited number of common units, without common unitholder approval (subject to applicable New York StockExchange ("NYSE") rules). We may also issue at any time an unlimited number of equity securities ranking junior or senior to the common units (including additionalpreferred units) without common unitholder approval (subject to applicable NYSE rules). In addition, we may issue additional common units upon the exercise of theoutstanding warrants held by Blackstone and GoldenTree. The issuance of additional common units or other equity securities of equal or senior rank will have thefollowing effects:•an existing unitholder’s proportionate ownership interest in NRP will decrease;•the amount of cash available for distribution on each unit may decrease; and•the relative voting strength of each previously outstanding unit may be diminished; and the market price of the common units may decline. Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price. If at any time our general partner and its affiliates own 80% or more of the common units, the general partner will have the right, but not the obligation, which itmay assign to any of its affiliates, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price generally equal to the thencurrent market price of the common units. As a result, unitholders may be required to sell their common units at a time when they may not desire to sell them or at a pricethat is less than the price they would like to receive. They may also incur a tax liability upon a sale of their common units. Cost reimbursements due to our general partner may be substantial and will reduce our cash available for distribution to unitholders. Prior to making any distribution on the common units, we reimburse our general partner and its affiliates, including officers and directors of the general partner, forall expenses incurred on our behalf. The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions. The general partnerhas sole discretion to determine the amount of these expenses. In addition, our general partner and its affiliates may provide us services for which we will be chargedreasonable fees as determined by the general partner. Conflicts of interest could arise among our general partner and us or the unitholders. These conflicts may include the following:•We do not have any employees and we rely solely on employees of affiliates of the general partner;•under our partnership agreement, we reimburse the general partner for the costs of managing and for operating the partnership;•the amount of cash expenditures, borrowings and reserves in any quarter may affect cash available to pay quarterly distributions to unitholders;•the general partner tries to avoid being liable for partnership obligations. The general partner is permitted to protect its assets in this manner by our partnershipagreement. Under our partnership agreement the general partner would not breach its fiduciary duty by avoiding liability for partnership obligations even if we canobtain more favorable terms without limiting the general partner’s liability;•under our partnership agreement, the general partner may pay its affiliates for any services rendered on terms fair and reasonable to us. The general partner mayalso enter into additional contracts with any of its affiliates on behalf of us. Agreements or contracts between us and our general partner (and its affiliates) are notnecessarily the result of arm’s-length negotiations; and•the general partner would not breach our partnership agreement by exercising its call rights to purchase limited partnership interests or by assigning its call rights toone of its affiliates or to us. In addition, Blackstone has certain consent rights and board appointment and observation rights. GoldenTree also has more limited consent rights. In the exerciseof their applicable consent rights and/or board rights, conflicts of interest could arise between us and our general partner on the one hand, and Blackstone orGoldenTree on the other hand. 21Table of Contents The control of our general partner may be transferred to a third party without unitholder consent. A change of control may result in defaults under certain of ourdebt instruments and the triggering of payment obligations under compensation arrangements. Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of ourunitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the general partner of our general partner from transferring its generalpartnership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the Board of Directors andofficers with its own choices and to control their decisions and actions. In addition, a change of control would constitute an event of default under our debt agreements. During the continuance of an event of default under our debtagreements, the administrative agent may terminate any outstanding commitments of the lenders to extend credit to us and/or declare all amounts payable by usimmediately due and payable. In addition, upon a change of control, the holders of the preferred units would have the right to require us to redeem the preferred units atthe liquidation preference or convert all of their preferred units into common units. A change of control also may trigger payment obligations under variouscompensation arrangements with our officers. Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business. Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligationsthat are expressly made without recourse to our general partner. Under Delaware law, however, a unitholder could be held liable for our obligations to the same extent asa general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constitutedparticipation in the "control" of our business. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under somecircumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution. Tax Risks to Our Unitholders Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes as well as our not being subject to a material amount of entity-leveltaxation by individual states. If the Internal Revenue Service ("IRS") were to treat us as a corporation for U.S. federal income tax purposes or we were to becomesubject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantiallyreduced. The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for U.S. federal income taxpurposes. Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposesunless we satisfy a "qualifying income" requirement. Based on our current operations and current Treasury Regulations, we believe we satisfy the qualifying incomerequirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifyingincome requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation asan entity. If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate andwould likely be liable for state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income,gains, losses, deductions or credits would flow through to our unitholders. Because tax would be imposed upon us as a corporation, our cash available for distributionto our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise andother forms of taxation. We currently own assets and conduct business in several states, many of which impose a margin or franchise tax. In the future, we may expandour operations. Imposition of a similar tax on us in a jurisdiction in which we operate or in other jurisdictions to which we may expand could substantially reduce thecash available for distribution to our unitholders. The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes ordiffering interpretations, possibly applied on a retroactive basis. The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units, may be modified by administrative,legislative or judicial changes or differing interpretations at any time. Members of Congress have frequently proposed and considered substantive changes to theexisting U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership taxtreatment. Recent proposals have provided for the expansion of the qualifying income exception for publicly traded partnerships in certain circumstances and otherproposals have provided for the total elimination of the qualifying income exception upon which we rely for our partnership tax treatment. In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. Therecan be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in amanner that could impact our ability to qualify as a partnership in the future. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult orimpossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable topredict whether any changes or other proposals will ultimately be enacted. Any future legislative changes could negatively impact the value of an investment in ourunits. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potentialeffect on your investment in our units. 22Table of Contents Certain U.S. federal income tax preferences currently available with respect to coal exploration and development may be eliminated as a result of futurelegislation. Changes to U.S. federal income tax laws have been proposed in a prior session of Congress that would eliminate certain key U.S. federal income tax preferencesrelating to coal exploration and development. These changes include, but are not limited to (i) repealing capital gains treatment of coal and lignite royalties,(ii) eliminating current deductions and 60-month amortization for exploration and development costs relating to coal and other hard mineral fossil fuels, and (iii) repealingthe percentage depletion allowance with respect to coal properties. If enacted, these changes would limit or eliminate certain tax deductions that are currently availablewith respect to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the valueof an investment in our units. Our unitholders are required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us. Our unitholders' share ofour portfolio income may be taxable to them even though they receive other losses from our activities. Because our unitholders are treated as partners to whom we allocate taxable income that could be different in amount than the cash we distribute, our unitholdersare required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cashdistributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax due from themwith respect to that income. For our unitholders subject to the passive loss rules, our current operations include portfolio activities (such as our coal and mineral royalty businesses) andpassive activities (such as our soda ash business). Any passive losses we generate will only be available to offset our passive income generated in the future and willnot be available to offset (i) our portfolio income, including income related to our coal and mineral royalty businesses, (ii) a unitholder’s income from other passiveactivities or investments, including investments in other publicly traded partnerships, or (iii) a unitholder’s salary or active business income. Thus, our unitholders'share of our portfolio income may be subject to U.S. federal income tax, regardless of other losses they may receive from us. We may engage in transactions to reduce our indebtedness and manage our liquidity that generate taxable income (including income and gain from the sale ofproperties and cancellation of indebtedness income) allocable to our unitholders, and income tax liabilities arising therefrom may exceed any distributions madewith respect to their units. We may engage in transactions to reduce our leverage and manage our liquidity that would result in income and gain to our unitholders without a correspondingcash distribution. For example, we may sell assets and use the proceeds to repay existing debt, in which case, our unitholders could be allocated taxable income and gainresulting from the sale without receiving a cash distribution. Further, we may pursue opportunities to reduce our existing debt, such as debt exchanges, debtrepurchases, or modifications of our existing debt that would result in “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to ourunitholders as ordinary taxable income. Our unitholders may be allocated income and gain from these transactions, and income tax liabilities arising therefrom mayexceed any distributions we make to our unitholders. The ultimate tax effect of any such income allocations will depend on the unitholder's individual tax position,including, for example, the availability of any suspended passive losses that may offset some portion of the allocable income. Our unitholders may, however, beallocated substantial amounts of ordinary income subject to taxation, without any ability to offset such allocated income against any capital losses attributable to theunitholder’s ultimate disposition of its units. Our unitholders are encouraged to consult their tax advisors with respect to the consequences to them. If the IRS contests the U.S. federal income tax positions we take, the market for our units may be adversely impacted and the cost of any IRS contest will reduce ourcash available for distribution to our unitholders. We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us.The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of thepositions we take. A court may not agree with some or all of the positions we take. Any contest by the IRS may materially and adversely impact the market for our unitsand the price at which they trade. In addition, our costs of any contest by the IRS will be borne indirectly by our unitholders and our general partner because the costswill reduce our cash available for distribution. If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes(including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to ourunitholders might be substantially reduced. Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (andsome states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extentpossible under these rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible,issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our general partner may elect tohave our unitholders and former unitholders take such audit adjustments into account and pay any resulting taxes (including applicable penalties or interest) inaccordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in allcircumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not ownunits in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cashavailable for distribution to our unitholders might be substantially reduced. 23Table of Contents Tax gain or loss on the disposition of our common units could be more or less than expected. If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in thosecommon units. Distributions in excess of a common unitholder's allocable share of our net taxable income result in a decrease in the tax basis in such unitholder'scommon units. Accordingly, the amount, if any, of such prior excess distributions with respect to the common units sold will, in effect, become taxable income to ourcommon unitholders if they sell such common units at a price greater than their tax basis in those common units, even if the price they receive is less than their originalcost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if our unitholders sell their common units, they may incur a taxliability in excess of the amount of cash they receive from the sale. A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, may be taxed as ordinary income due topotential recapture items, including depletion and depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of unitsif the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case ofindividuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, such unitholder may recognize ordinary income from ourallocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the saleof units. Our unitholders may be subject to limitation on their ability to deduct interest expense incurred by us. In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However,our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation,our adjusted taxable income is computed without regard to any business interest expense or business interest income. If our “business interest” is subject to limitationunder these rules, our unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them. As a result, unitholders maybe subject to limitation on their ability to deduct interest expense incurred by us. Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them. Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them.For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will beunrelated business taxable income and will be taxable to them. Additionally, all or part of any gain recognized by such tax-exempt organization upon a sale or otherdisposition of our units may be unrelated business taxable income and may be taxable to them. Tax-exempt entities should consult a tax advisor before investing in ourunits. Non-U.S. unitholders will be subject to U.S. federal income taxes and withholding with respect to their income and gain from owning our units. Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade orbusiness. Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade orbusiness. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sellsor otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit. In addition to the withholdingtax imposed on distributions of effectively connected income, distributions to a non-U.S. unitholder will also be subject to a 10% withholding tax on the amount of anydistribution in excess of our cumulative net income. As we do not compute our cumulative net income for such purposes due to the complexity of the calculation andlack of clarity in how it would apply to us, we intend to treat all of our distributions as being in excess of our cumulative net income for such purposes and subject tosuch 10% withholding tax. Accordingly, distributions to a non-U.S. unitholder will be subject to a combined withholding tax rate equal to the sum of the highestapplicable effective tax rate and 10%. Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the “amount realized”by the transferor unless the transferor certifies that it is not a foreign person. While the determination of a partner’s “amount realized” generally includes any decreaseof a partner’s share of the partnership’s liabilities, the Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly tradedpartnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor,and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. For a transfer of interests in a publiclytraded partnership that is effected through a broker on or after January 1, 2023, the obligation to withhold is imposed on the transferor’s broker. Current and prospectivenon-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units. We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challengethis treatment, which could adversely affect the value of the common units. Because we cannot match transferors and transferees of our common units and for other reasons, we have adopted depreciation and amortization positions thatmay not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefitsavailable to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact onthe value of our common units or result in audit adjustments to our unitholders' tax returns. 24Table of Contents We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge thesemethodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units. In determining the items of income, gain, loss and deduction allocable to our unitholders, including when we issue additional units, we must determine the fairmarket value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market valueestimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge thesevaluation methods and the resulting allocations of income, gain, loss and deduction. A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to ourunitholders. It also could affect the amount of gain recognized from the sale of our common units, have a negative impact on the value of our common units or result inaudit adjustments to our unitholders’ tax returns without the benefit of additional deductions. We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownershipof our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, whichcould change the allocation of items of income, gain, loss and deduction among our unitholders. We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon theownership of our common units on the first day of each month (the "Allocation Date"), instead of on the basis of the date a particular unit is transferred. Similarly, wegenerally allocate (i) certain deductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets, and (iii) in the discretionof the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow asimilar monthly simplifying convention, but such regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challengeour proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. A unitholder whose units are the subject of a securities loan (e.g., a loan to a "short seller" to cover a short sale of units) may be considered as having disposed ofthose units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and mayrecognize gain or loss from the disposition. Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subjectof a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner withrespect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the periodof the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by theunitholder as to those units could be fully taxable as ordinary income. Our unitholders desiring to assure their status as partners and avoid the risk of gain recognitionfrom a loan of their units are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit theirbrokers from borrowing their units. As a result of investing in our units, our unitholders are likely subject to state and local taxes and return filing requirements in jurisdictions where we operate orown or acquire property. In addition to U.S. federal income taxes, our unitholders are likely subject to other taxes, including state and local taxes, unincorporated business taxes and estate,inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if our unitholdersdo not live in any of those jurisdictions. Our unitholders are likely required to file state and local income tax returns and pay state and local income taxes in some or all ofthese various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We own property and conduct business ina number of states in the United States. Most of these states impose an income tax on individuals, corporations and other entities. As we make acquisitions or expandour business, we may own assets or conduct business in additional states that impose a personal income tax. It is the unitholder's responsibility to file all U.S. federal,state and local tax returns and pay any taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of such tax returns,the payment of such taxes, and the deductibility of any taxes paid. General Risks Our business is subject to cybersecurity risks. Our business is increasingly dependent on information technologies and services. Threats to information technology systems associated with cybersecurity risksand cyber incidents or attacks continue to grow. Although we utilize various procedures and controls to mitigate our exposure to such risks, cybersecurity attacks andother cyber events are evolving, unpredictable, and sometimes difficult to detect, and could lead to unauthorized access to sensitive information or render data orsystems unusable. While we presently maintain insurance coverage to protect against cybersecurity risks, we cannot ensure that it will be sufficient to cover any particular losses wemay experience as a result of such cyber-attacks. Any cyber incident could have a material adverse effect on our business, financial condition and results of operations. 25Table of Contents ITEM 1B. UNRESOLVED STAFF COMMENTS None. ITEM 3. LEGAL PROCEEDINGS We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannotbe predicted with certainty, management believes these ordinary course matters will not have a material effect on our financial position, liquidity or operations. ITEM 4. MINE SAFETY DISCLOSURES None. 26Table of Contents PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES NRP Common Units Our common units are listed and traded on the NYSE under the symbol "NRP." As of February 16, 2023, there were approximately 11,000 beneficial and registeredholders of our common units. The computation of the approximate number of unitholders is based upon a broker survey. ITEM 6. [RESERVED] ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Introduction The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction withour consolidated financial statements and footnotes included elsewhere in this filing. Our discussion and analysis consists of the following subjects:•Executive Overview•Results of Operations•Liquidity and Capital Resources•Inflation•Environmental Regulation•Related Party Transactions•Summary of Critical Accounting Estimates•Recent Accounting Standards As used in this Item 7, unless the context otherwise requires: "we," "our," "us" and the "Partnership" refer to Natural Resource Partners L.P. and, where thecontext requires, our subsidiaries. References to "NRP" and "Natural Resource Partners" refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC orany of Natural Resource Partners L.P.’s subsidiaries. References to "Opco" refer to NRP (Operating) LLC, a wholly owned subsidiary of NRP, and its subsidiaries. NRPFinance Corporation ("NRP Finance") is a wholly owned subsidiary of NRP and was a co-issuer with NRP on the 9.125% senior notes due 2025 (the "2025 SeniorNotes"). 27Table of Contents Non-GAAP Financial Measures Distributable Cash Flow Distributable cash flow ("DCF") represents net cash provided by (used in) operating activities of continuing operations plus distributions from unconsolidatedinvestment in excess of cumulative earnings, proceeds from asset sales and disposals, including sales of discontinued operations, and return of long-term contractreceivables, less maintenance capital expenditures. DCF is not a measure of financial performance under GAAP and should not be considered as an alternative to cashflows from operating, investing or financing activities. DCF may not be calculated the same for us as for other companies. In addition, DCF presented below is notcalculated or presented on the same basis as distributable cash flow as defined in our partnership agreement, which is used as a metric to determine whether we are ableto increase quarterly distributions to our common unitholders. DCF is a supplemental liquidity measure used by our management and by external users of our financialstatements, such as investors, commercial banks, research analysts and others to assess our ability to make cash distributions and repay debt. Free Cash Flow Free cash flow ("FCF") represents net cash provided by (used in) operating activities of continuing operations plus distributions from unconsolidated investmentin excess of cumulative earnings and return of long-term contract receivables, less maintenance and expansion capital expenditures and cash flow used in acquisitioncosts classified as investing or financing activities. FCF is calculated before mandatory debt repayments. FCF is not a measure of financial performance under GAAPand should not be considered as an alternative to cash flows from operating, investing or financing activities. FCF may not be calculated the same for us as for otherand should not be considered as an alternative to cash flows from operating, investing or financing activities. FCF may not be calculated the same for us as for othercompanies. FCF is a supplemental liquidity measure used by our management and by external users of our financial statements, such as investors, commercial banks,research analysts and others to assess our ability to make cash distributions and repay debt. Cash Flow Cushion Cash flow cushion represents net cash provided by (used in) operating activities of continuing operations plus distributions from unconsolidated investment inexcess of cumulative earnings and return of long-term contract receivables; less maintenance and expansion capital expenditures, cash flow used in acquisition costsclassified as investing or financing activities, one-time beneficial items, mandatory Opco debt repayments, preferred unit distributions and redemption of PIK units,common unit distributions and warrant cash settlements. Cash flow cushion is not a measure of financial performance under GAAP and should not be considered as analternative to cash flows from operating, investing or financing activities. Cash flow cushion is a supplemental liquidity measure used by our management to assess ourability to make or raise cash distributions to our common and preferred unitholders and our general partner and repay debt or redeem preferred units. Adjusted EBITDA Adjusted EBITDA is a non-GAAP financial measure that we define as net income (loss) less equity earnings from unconsolidated investment, net incomeattributable to non-controlling interest and gain on reserve swap; plus total distributions from unconsolidated investment, interest expense, net, debt modificationexpense, loss on extinguishment of debt, depreciation, depletion and amortization and asset impairments. Adjusted EBITDA should not be considered an alternative to,or more meaningful than, net income or loss, net income or loss attributable to partners, operating income, cash flows from operating activities or any other measure offinancial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations. There are significantlimitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring items that materially affect our netincome (loss), the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDA reported by differentcompanies. In addition, Adjusted EBITDA presented below is not calculated or presented on the same basis as Consolidated EBITDA as defined in our partnershipagreement or Consolidated EBITDDA as defined in Opco's debt agreements. See "Item 8. Financial Statements and Supplementary Data—Note 11. Debt, Net" includedelsewhere in this Annual Report on Form 10-K for a description of Opco’s debt agreements. Adjusted EBITDA is a supplemental performance measure used by ourmanagement and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess the financial performance ofour assets without regard to financing methods, capital structure or historical cost basis. Leverage Ratio Leverage ratio represents the outstanding principal of NRP's debt at the end of the period divided by the last twelve months' Adjusted EBITDA as definedabove. NRP believes that leverage ratio is a useful measure to management and investors to evaluate and monitor the indebtedness of NRP relative to its ability togenerate income to service such debt and in understanding trends in NRP’s overall financial condition. Leverage ratio may not be calculated the same for us as for othercompanies and is not a substitute for, and should not be used in conjunction with, GAAP financial ratios. 28Table of Contents Executive Overview We are a diversified natural resource company engaged principally in the business of owning, managing and leasing a diversified portfolio of mineral properties inthe United States, including interests in coal and other natural resources and own a non-controlling 49% interest in Sisecam Wyoming LLC ("Sisecam Wyoming"), atrona ore mining and soda ash production business. Our common units trade on the New York Stock Exchange under the symbol "NRP." Our business is organized intotwo operating segments: Mineral Rights—consists of approximately 13 million acres of mineral interests and other subsurface rights across the United States. If combined in a single tract,our ownership would cover roughly 20,000 square miles. Our ownership provides critical inputs for the manufacturing of steel, electricity and basic building materials, aswell as opportunities for carbon sequestration and renewable energy. We are working to strategically redefine our business as a key player in the transitional energyeconomy in the years to come. Soda Ash—consists of our 49% non-controlling equity interest in Sisecam Wyoming, a trona ore mining and soda ash production business located in the GreenRiver Basin of Wyoming. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into the glass and chemicalsindustries. Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these departments include interest andfinancing, corporate headquarters and overhead, centralized treasury, legal and accounting and other corporate-level activity not specifically allocated to a segment. Our financial results by segment for the year ended December 31, 2022 are as follows: Operating Segments Corporate and (In thousands) Mineral Rights Soda Ash Financing Total Revenues and other income $329,167 $59,795 $— $388,962 Net income (loss) $267,448 $59,635 $(58,591) $268,492 Asset impairments 4,457 — — 4,457 Net income (loss) excluding asset impairments $271,905 $59,635 $(58,591) $272,949 Adjusted EBITDA (1) $294,424 $44,675 $(21,852) $317,247 Cash flow provided by (used in) continuing operations Operating activities $262,807 $44,672 $(40,641) $266,838 Investing activities $2,806 $— $(118) $2,688 Financing activities $(614) $— $(365,341) $(365,955)Distributable cash flow (1) $265,613 $44,672 $(40,759) $269,526 Free cash flow (1) $264,530 $44,672 $(40,759) $268,443 Cash flow cushion (1) N/A N/A N/A $145,084 (1)See"—Results of Operations" below for reconciliations to the most comparable GAAP financial measures. 29Table of Contents Current Results/Market Commentary Business Outlook and Quarterly Distributions We generated $266.8 million of operating cash flow and $268.4 million of free cash flow during the year ended December 31, 2022, and ended the yearwith $99.1 million of liquidity consisting of $39.1 million of cash and cash equivalents and $60 million of borrowing capacity under our Opco Credit Facility. During theyear, we refinanced, upsized, and extended our Opco Credit Facility to $130 million due 2027. Also during the year, we permanently retired all $300 million of our 2025Senior Notes. As of December 31, 2022 our leverage ratio was 0.5x. In February 2023, the Board of Directors declared a cash distribution of $0.75 per common unit of NRP with respect to the fourth quarter of 2022 as well as a $7.5million cash distribution on the preferred units with respect to the fourth quarter of 2022. Additionally, NRP has announced it will pay a one-time, specialcash distribution of $2.43 in March 2023 to help cover unitholder tax liabilities for 2022. Future distributions on our common and preferred units will be determined on aquarterly basis by the Board of Directors. The Board of Directors considers numerous factors each quarter in determining cash distributions, including profitability, cashflow, debt service obligations, market conditions and outlook, estimated unitholder income tax liability and the level of cash reserves that the Board determines isnecessary for future operating and capital needs. In February 2023, we received a notice from holders of our Class A Preferred Units exercising their right to either convert or redeem, at the election of NRP, anaggregate of 47,499 Class A Preferred Units. We chose to redeem the preferred units for $47.5 million in cash plus any accrued and unpaid distributions, utilizing cash onhand and borrowings under our revolving credit facility. Of the originally issued 250,000 Class A Preferred Units, 202,501 Class A Preferred Units remain outstanding asof the date of this report. Mineral Rights Business Segment Metallurgical coal prices reached historical highs and were the primary driver of strong segment performance. Numerous factors continue to provide support formet pricing. Supply chain disruptions, labor shortages and years of underinvestment in new coal production capacity continue to undermine producers’ ability to bringnew production online to meet demand. While met prices have pulled back from the peaks reached last year, we continue to believe met prices will remain well-supportedfor the foreseeable future. Thermal coal prices also reached record highs in 2022, but have declined significantly in recent months due to unusually warm weather in Europe and NorthAmerica as well as lower natural gas prices. While we do not expect to see thermal prices rebound to last year’s levels, many of the factors that provided support toprices over the last year still exist. Boycotts of Russian coal continue to force European buyers to source coal from other regions, including the U.S. Operators willcontinue to be burdened by labor shortages, pressure from governments, regulators, activists, and capital providers, which will limit ability to increase thermalproduction to meet demand. China appears to be relaxing its three-year ban on Australian coal imports with the recent approvals for several Chinese companies to buyAustralian coal. Additional demand from a Chinese economy emerging from a zero-COVID policy should provide additional support for prices. We expect these factorsto keep thermal prices elevated relative to historical levels for the foreseeable future We continue to explore and identify carbon neutral revenue sources across our large portfolio of land and mineral assets. The types of opportunities include thesequestration of carbon dioxide underground and in standing forests, and the generation of green electricity using geothermal, solar, and wind energy. We own therights to sequester carbon dioxide ("CO2") on approximately 3.5 million acres of pore space in the southern United States. As announced previously, in the first quarterof 2022 we executed our first subsurface CO2 sequestration lease on 75,000 acres of underground pore space we own in southwest Alabama with the potential to storeover 300 million metric tons of CO2. In October of 2022, we announced our second subsurface CO2 transaction with the execution of a lease for approximately 65,000acres of pore space we control near southeast Texas with estimated storage capacity of at least 500 million metric tons of CO2. In total, we have approximately 140,000acres of pore space under lease for carbon sequestration with estimated CO2 storage capacity of 800 million metric tons. While the timing and likelihood of additionalcash flows being realized from these activities is uncertain, we believe our large ownership footprint throughout the United States provides additional opportunities tocreate value in this regard with minimal capital investment by us. Soda Ash Business Segment Revenues and other income during the year ended December 31, 2022 were higher by $37.9 million compared to the prior year period primarily as a result ofincreased international sales prices. Cash provided by operating activities and free cash flow during the year ended December 31, 2022 increased $33.6 million ascompared to the prior year period due to Sisecam Wyoming reinstating its regular quarterly cash distributions beginning in the fourth quarter of 2021. Strong international sales at Sisecam Wyoming for the year ended December 31, 2022, more than offset input cost inflation, supply chain difficulties, and softeningdemand in the second half of the year due to China's Zero-Covid policy and concerns of slowing economic growth. 30Table of Contents Results of Operations Year Ended December 31, 2022 and 2021 Compared Revenues and Other Income The following table includes our revenues and other income by operating segment: For the Year Ended December 31, Percentage Operating Segment (In thousands) 2022 2021 Increase Change Mineral Rights $329,167 $194,493 $134,674 69%Soda Ash 59,795 21,871 37,924 173%Total $388,962 $216,364 $172,598 80% 31Table of Contents The changes in revenues and other income are discussed for each of the operating segments below: Mineral Rights The following table presents coal sales volumes, coal royalty revenue per ton and coal royalty revenues by major coal producing region, the significant categoriesof other revenues and other income: For the Year Ended December 31, Increase Percentage (In thousands, except per ton data) 2022 2021 (Decrease) Change Coal sales volumes (tons) Appalachia Northern 1,696 1,335 361 27%Central 13,646 12,279 1,367 11%Southern 1,784 1,571 213 14%Total Appalachia 17,126 15,185 1,941 13%Illinois Basin 11,135 9,388 1,747 19%Northern Powder River Basin 4,288 3,151 1,137 36%Gulf Coast 385 55 330 600%Total coal sales volumes 32,934 27,779 5,155 19% Coal royalty revenue per ton Appalachia Northern $8.75 $6.51 $2.24 34%Central 10.47 5.71 4.76 83%Southern 13.50 9.14 4.36 48%Illinois Basin 2.50 2.12 0.38 18%Northern Powder River Basin 4.07 3.54 0.53 15%Gulf Coast 0.58 0.60 (0.02) (3)%Combined average coal royalty revenue per ton 6.90 4.47 2.43 54% Coal royalty revenues Appalachia Northern $14,836 $8,691 $6,145 71%Central 142,930 70,149 72,781 104%Southern 24,076 14,355 9,721 68%Total Appalachia 181,842 93,195 88,647 95%Illinois Basin 27,856 19,917 7,939 40%Northern Powder River Basin 17,437 11,151 6,286 56%Gulf Coast 223 33 190 576%Unadjusted coal royalty revenues 227,358 124,296 103,062 83%Coal royalty adjustment for minimum leases (402) (20,207) 19,805 98%Total coal royalty revenues $226,956 $104,089 $122,867 118% Other revenues Production lease minimum revenues $5,854 $14,269 $(8,415) (59)%Minimum lease straight-line revenues 18,792 20,564 (1,772) (9)%Carbon neutral initiative revenues 8,600 13,790 (5,190) (38)%Wheelage revenues 13,961 10,065 3,896 39%Property tax revenues 5,878 6,028 (150) (2)%Coal overriding royalty revenues 3,434 4,367 (933) (21)%Lease amendment revenues 3,201 4,696 (1,495) (32)%Aggregates royalty revenues 3,299 1,889 1,410 75%Oil and gas royalty revenues 16,161 4,506 11,655 259%Other revenues 877 933 (56) (6)%Total other revenues $80,057 $81,107 $(1,050) (1)%Royalty and other mineral rights $307,013 $185,196 $121,817 66%Transportation and processing services revenues 21,072 9,052 12,020 133%Gain on asset sales and disposals 1,082 245 837 342%Total Mineral Rights segment revenues and other income $329,167 $194,493 $134,674 69% 32Table of Contents Coal Royalty Revenues Approximately 70% of coal royalty revenues and approximately 45% of coal royalty sales volumes were derived from metallurgical coal during the year endedDecember 31, 2022. Total coal royalty revenues increased $122.9 million from 2021 to 2022. Strong coal prices in 2022 were primarily driven by improved demandcombined with a limited ability for operators to increase production due to ongoing labor shortages, global supply chain interruptions, and limited access to capital. Thediscussion by region is as follows: •Appalachia: Coal royalty revenues increased $88.6 million primarily due to increased coal sales prices and volumes during the year ended December 31, 2022, ascompared to the prior year.•Illinois Basin: Coal royalty revenues increased $7.9 million primarily due to higher sales volumes and increased sales prices during the year ended December 31,2022 as compared during the prior year. Revenues recognized from Foresight in 2021 were fixed as a result of the lease amendment the Partnership entered into withForesight in 2020 pursuant to which Foresight agreed to pay NRP fixed cash payments in 2020 and 2021 to satisfy all obligations arising out of the existing variouscoal mining leases and transportation infrastructure fee agreements between the Partnership and Foresight. Revenues from Foresight in 2022 represent traditionalroyalty and minimum payments.•Northern Powder River Basin: Coal royalty revenues increased $6.3 million primarily due to increased sales volumes as our lessee mined more on our propertyduring 2022 as compared to 2021in accordance with its mine plan. Other Revenues Other revenues decreased $1.1 million during the year ended December 31, 2022 as compared to the prior year primarily due to the following:•An $8.4 million decrease in production lease minimum revenues primarily due to the lease amendment with Foresight whereas transportation and processingrevenues were based on the recognition of a fixed amount in 2021.•A $5.2 million decrease in carbon neutral initiative revenues as compared to the prior year. Revenues recognized in 2022 related to carbon neutral transactions thatincluded subsurface CO2 storage and geothermal while revenues recognized in 2021 related to forest CO2 sequestration revenues. These decreases were partially offset by an $11.7 million increase in oil and gas royalty revenues primarily due to new wells and increased natural gas prices ascompared to the prior year. Transportation and Processing Services Revenues Transportation and processing services revenues increased $12.0 million during the year ended December 31, 2022 as compared to the prior year primarily due tothe lease amendment with Foresight whereas transportation and processing revenues were based on the recognition of a fixed amount in 2021. Revenues from Foresightin 2022 represented traditional royalty and minimum payments and were greater than the fixed revenue from 2021. Soda Ash Revenues and other income related to our Soda Ash segment increased $37.9 million compared to the prior year primarily as a result of increased international salesprices. Operating and Other Expenses The following table presents the significant categories of our consolidated operating and other expenses: For the Year Ended December 31, Increase Percentage (In thousands) 2022 2021 (Decrease) Change Operating expenses Operating and maintenance expenses $34,903 $27,049 $7,854 29%Depreciation, depletion and amortization 22,519 19,075 3,444 18%General and administrative expenses 21,852 17,360 4,492 26%Asset impairments 4,457 5,102 (645) (13)%Total operating expenses $83,731 $68,586 $15,145 22% Other expenses, net Interest expense, net $26,274 $38,876 $(12,602) (32)%Loss on extinguishment of debt 10,465 — 10,465 100%Total other expenses, net $36,739 $38,876 $(2,137) (5)% Total operating expenses increased $15.1 million primarily due to the following: •A $7.9 million increase in operating and maintenance expenses primarily as a result of higher overriding royalty expense from an agreement with WPPLP in 2022 ascompared to 2021. This overriding royalty expense is fully offset by coal royalty revenue we receive from this property.•A $4.5 million increase in general and administrative expenses primarily due to increased incentive compensation expense incurred during 2022 as a result of thePartnership's improved performance as compared to the prior year.•A $3.4 million increase in depreciation, depletion and amortization expense primarily as a result of higher Illinois Basin coal royalty sales volumes during the yearended December 31, 2022, as compared to the prior year. Total other expenses, net decreased $2.1 million primarily due to a $12.6 million decrease in interest expense, net as a result of less debt outstanding as compared tothe prior year, partially offset by a $10.5 million loss on early extinguishment of debt related to the premiums and fees incurrent and write-off of debt issuance costsassociated with the retirement of the 2025 Senior Notes during the year ended December 31, 2022. 33Table of Contents Adjusted EBITDA (Non-GAAP Financial Measure) The following table reconciles net income (loss) (the most comparable GAAP financial measure) to Adjusted EBITDA by business segment: Operating Segments Corporate and For the Year Ended (In thousands) Mineral Rights Soda Ash Financing Total December 31, 2022 Net income (loss) $267,448 $59,635 $(58,591) $268,492 Less: equity earnings from unconsolidated investment — (59,795) — (59,795)Add: total distributions from unconsolidated investment — 44,835 — 44,835 Add: interest expense, net — — 26,274 26,274 Add: loss on extinguishment of debt — — 10,465 10,465 Add: depreciation, depletion and amortization 22,519 — — 22,519 Add: asset impairments 4,457 — — 4,457 Adjusted EBITDA $294,424 $44,675 $(21,852) $317,247 December 31, 2021 Net income (loss) $143,412 $21,702 $(56,212) $108,902 Less: equity earnings from unconsolidated investment — (21,871) — (21,871)Add: total distributions from unconsolidated investment — 11,270 — 11,270 Add: interest expense, net 24 — 38,852 38,876 Add: depreciation, depletion and amortization 19,075 — — 19,075 Add: asset impairments 5,102 — — 5,102 Adjusted EBITDA $167,613 $11,101 $(17,360) $161,354 Net income increased $159.6 million primarily due to the increases in revenues and other income, partially offset by increased operating expenses, both asdiscussed above. Adjusted EBITDA increased $155.9 million primarily due to a $126.8 million increase in Adjusted EBITDA within our Mineral Rights segment as aresult of higher revenues and other income during the year ended December 31, 2022 as discussed above and a $33.6 million increase in Adjusted EBITDA within ourSoda Ash segment as a result of higher cash distributions received from Sisecam Wyoming during the year ended December 31, 2022 as compared to the prior year dueto Sisecam Wyoming reinstating its regular quarterly cash distributions beginning in the fourth quarter of 2021. Distributable Cash Flow ("DCF"), Free Cash Flow ("FCF") and Cash Flow Cushion (Non-GAAP Financial Measures) The following table presents the three major categories of the statement of cash flows by business segment: Operating Segments For the Year Ended (In thousands) Mineral Rights Soda Ash Corporate and Financing Total December 31, 2022 Cash flow provided by (used in) continuing operations Operating activities $262,807 $44,672 $(40,641) $266,838 Investing activities 2,806 — (118) 2,688 Financing activities (614) — (365,341) (365,955) December 31, 2021 Cash flow provided by (used in) continuing operations Operating activities $159,845 $11,106 $(49,147) $121,804 Investing activities 2,412 — — 2,412 Financing activities (1,132) — (87,354) (88,486) 34Table of Contents The following tables reconcile net cash provided by (used in) operating activities (the most comparable GAAP financial measure) by business segment to DCF,FCF and cash flow cushion: Operating Segments For the Year Ended (In thousands) Mineral Rights Soda Ash Corporate and Financing Total December 31, 2022 Net cash provided by (used in) operating activities of continuing operations $262,807 $44,672 $(40,641) $266,838 Add: proceeds from asset sales and disposals 1,083 — — 1,083 Add: return of long-term contract receivable 1,723 — — 1,723 Less: maintenance capital expenditures — — (118) (118)Distributable cash flow $265,613 $44,672 $(40,759) $269,526 Less: proceeds from asset sales and disposals (1,083) — — (1,083)Free cash flow $264,530 $44,672 $(40,759) $268,443 Less: mandatory Opco debt repayments (39,396)Less: preferred unit distributions and redemption of PIK units (49,579)Less: common unit distributions (34,384)Cash flow cushion $145,084 Operating Segments For the Year Ended (In thousands) Mineral Rights Soda Ash Corporate and Financing Total December 31, 2021 Net cash provided by (used in) operating activities of continuing operations $159,845 $11,106 $(49,147) $121,804 Add: proceeds from asset sales and disposals 249 — — 249 Add: return of long-term contract receivable 2,163 — — 2,163 Distributable cash flow $162,257 $11,106 $(49,147) $124,216 Less: proceeds from asset sales and disposals (249) — — (249)Less: acquisition costs (1,000) — — (1,000)Free cash flow $161,008 $11,106 $(49,147) $122,967 Less: mandatory Opco debt repayments (39,396)Less: preferred unit distributions (15,571)Less: common unit distributions (22,645)Less: warrant cash settlement (9,183)Cash flow cushion $36,172 Cash provided by operating activities, DCF and FCF increased $145.0 million, $145.3 million and $145.5 million, respectively, primarily due to the following: •Mineral Rights Segment: Cash provided by operating activities, DCF and FCF increased $103.0 million, $103.4 million and $103.5 million, respectivelyprimarily due to the segment's increase in revenues and other income as discussed above. •Soda Ash Segment: Cash provided by operating activities, DCF and FCF increased $33.6 million as a result of higher cash distributions received fromSisecam Wyoming in 2022 as compared to the prior year as discussed above. •Corporate and Financing Segment: Cash used by operating activities decreased $8.5 million and DCF and FCF increased $8.4 million primarily due tolower cash paid for interest in 2022 as a result of the repayments of our 2025 Senior Notes during the year. Cash flow cushion increased $108.9 million as a result of the increase in FCF discussed above and $9.2 million of cash used to settle the exercise of certain of ourwarrants in 2021, partially offset by: •$34.0 million of increased cash paid with respect to our preferred units. In 2021 we paid half of our preferred unit distributions in kind and in 2022 wepaid all of our preferred unit distributions in cash and redeemed the outstanding paid-in-kind units. •$11.7 million of increased cash used for common unit distributions as a result of increasing our common unit distributions to $0.75/unit beginning inthe second quarter of 2022. For discussion of our Results of Operations comparing 2021 to 2020, refer to our 2021 Annual Report on Form 10-K filed March 15, 2022 under Part II, "Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations." 35Table of Contents Liquidity and Capital Resources Current Liquidity As of December 31, 2022, we had total liquidity of $99.1 million, consisting of $39.1 million of cash and cash equivalents and $60 million in borrowing capacityunder our Opco Credit Facility. We have debt service obligations, including approximately $40 million of principal repayments on Opco’s senior notes in 2023. Asdiscussed previously, during 2022 we permanently retired all of our 9.125% Senior Notes due 2025 and had $70 million drawn on our Opco Credit Facility as of December31, 2022. We believe our liquidity position provides us with the flexibility to continue paying down debt and manage our business. As of December 31, 2022 our leverageratio was 0.5x. The following table calculates our leverage ratio: (In thousands) For the Year EndedDecember 31, 2022 Adjusted EBITDA $317,247 Debt—at December 31, 2022 $169,087 Leverage Ratio 0.5x Cash Flows Year Ended December 31, 2022 and 2021 Compared Cash flows provided by operating activities increased $145.0 million, from $121.8 million in the year ended December 31, 2021 to $266.8 million in the year endedDecember 31, 2022 primarily related to increased revenues and other income within our Mineral Rights segment, higher cash distributions received from SisecamWyoming, and less cash paid for interest as compared to the prior year, all as discussed above. Cash flows used in financing activities increased $277.5 million, from $88.5 million in the year ended December 31, 2021 to $366.0 million in the year endedDecember 31, 2022 primarily due to the following: •$300.0 million of cash used to retire all of our 2025 Senior Notes in 2022; •$19.6 million of cash used to redeem the preferred units paid-in-kind during the first quarter of 2022; •$14.4 million of increased cash used for preferred unit distributions as a result of paying all of our preferred unit distributions in cash in 2022 ascompared to a portion in kind in 2021; •$11.9 million of increased cash used for other items, net, which primarily related to the premiums paid related to the repayment of the 2025 Senior Notesin 2022; and •$11.7 million of increased cash used for distributions to common unitholders and the general partner as a result of increasing our common unitdistributions to $0.75/unit beginning in the second quarter of 2022. These increases in cash flow used were partially offset by $70 million of borrowings on our Opco Credit Facility in 2022 and $9.2 million of cash used in 2021 tosettle the exercise of certain of our warrants. For discussion of our Cash Flows comparing 2021 to 2020, refer to our 2021 Annual Report on Form 10-K filed March 15, 2022 under Part II, "Item 7. Management'sDiscussion and Analysis of Financial Condition and Results of Operations." 36Table of Contents Capital Resources and Obligations Debt, Net We had the following debt outstanding as of December 31, 2022 and 2021: December 31, (In thousands) 2022 2021 Current portion of long-term debt, net $39,076 $39,102 Long-term debt, net 129,205 394,443 Total debt, net $168,281 $433,545 We have been and continue to be in compliance with the terms of the financial covenants contained in our debt agreements. For additional information regardingour debt and the agreements governing our debt, including the covenants contained therein, see "Item 8. Financial Statements and Supplementary Data—Note 11. Debt,Net" in this Annual Report on Form 10-K. Debt Obligations The following table reflects our long-term, non-cancelable debt obligations as of December 31, 2022: Payments Due by Period Debt Obligations (In thousands) Total 2023 2024 2025 2026 2027 Thereafter NRP: Debt principal payments $— $— $— $— $— $— $— Debt interest payments — — — — — — — Opco: Debt principal payments (including currentmaturities) (1) 169,087 39,396 31,028 14,332 14,331 70,000 — Debt interest payments (2) 9,794 4,895 2,724 1,450 725 — — Total $178,881 $44,291 $33,752 $15,782 $15,056 $70,000 $— (1)The amounts indicated in the table include principal due on Opco’s senior notes and credit facility. (2)The amounts indicated in the table include interest due on Opco’s senior notes. Inflation Inflation in the United States has been relatively low in previous years, and despite rising costs beginning in 2021 and continuing into 2022, inflation did not havea material impact on operations for the years ended December 31, 2022, 2021 and 2020. Environmental Regulation For additional information on environmental regulation that may have a material impact on our business, see "Items 1. and 2. Business and Properties—Regulationand Environmental Matters." Related Party Transactions The information required by this Item is included under "Item 8. Financial Statements and Supplementary Data—Note 13. Related Party Transactions" and "Item13. Certain Relationships and Related Transactions, and Director Independence" in this Annual Report on Form 10-K and is incorporated by reference herein. 37Table of Contents Summary of Critical Accounting Estimates Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management tomake estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See "Item 8. Financial Statements and SupplementaryData—Note 2. Summary of Significant Accounting Policies" in the audited Consolidated Financial Statements of this Form 10-K for discussion of our significantaccounting policies. The following critical accounting policies are affected by estimates and assumptions used in the preparation of Consolidated Financial Statements.We evaluate our estimates and assumptions on a regular basis. Actual results could differ from those estimates. Revenues Mineral Rights Segment Revenues Royalty-based leases. Approximately two-thirds of our royalty-based leases have initial terms of five to 40 years, with substantially all lessees having the optionto extend the lease for additional terms. For these types of leases, the lessees generally make payments to us based on the greater of a percentage of the gross salesprice or a fixed price per ton of mineral mined and sold. Most of our coal and aggregates royalty leases require the lessee to pay quarterly or annual minimum amounts,either made in advance or arrears, which are generally recoupable through actual royalty production over certain time periods that generally range from three to fiveyears. We have defined our coal and aggregates royalty lease performance obligation as providing the lessee the right to mine and sell our coal or aggregates over thelease term. We then evaluated the likelihood that consideration we expected to receive from our lessees resulting from production would exceed consideration expectedto be received from minimum payments over the lease term. As a result of this evaluation, revenue recognition from our royalty-based leases is based on either production or minimum payments as follows:•Production Leases: Leases for which we expect that consideration from production will be greater than consideration from minimums over the lease term. Revenuefor these leases is recognized over time based on production as royalty revenues, as applicable. Deferred revenue from minimums is recognized as royalty revenueswhen recoupment occurs or as production lease minimum revenues when the recoupment period expires. In addition, we recognize breakage revenue from minimumswhen we determine that recoupment is remote. This breakage revenue is included in production lease minimum revenues.•Minimum Leases: Leases for which we expect that consideration from minimums will be greater than consideration from production over the lease term. Revenue forthese leases is recognized straight-line over the lease term based on the minimum consideration amount as minimum lease straight-line revenues. This evaluation is performed at the inception of the lease and only reassessed upon modification or renewal of the lease. Oil and gas related revenues consist of revenues from royalties and overriding royalties and are recognized on the basis of volume of hydrocarbons sold bylessees and the corresponding revenues from those sales. Also included within oil and gas royalty revenues are lease bonus payments, which are generally paid uponthe execution of a lease. We also have overriding royalty revenue interests in certain of our coal and aggregates mineral rights. Revenue from these interests isrecognized over time based on when the coal is sold. Carbon neutral initiative revenues. Revenues related to consideration received from carbon neutral initiatives that are recognized at a point in time uponsatisfaction of our performance obligation. Wheelage revenues. Revenues related to fees collected per ton to transport foreign coal across property we own that is recognized over time as transportationacross our property occurs. Other revenues. Other revenues consist primarily of rental payments and surface damage fees related to certain land we own and are recognized straight-line overtime as it is earned. Other revenues also include property tax revenues. The majority of property taxes paid on our properties are reimbursable by the lessee and arerecognized on a gross basis over time which affects the reimbursement of property taxes by the lessee. Property taxes we pay are included in operating and maintenanceexpenses on our Consolidated Statements of Comprehensive Income (Loss). Transportation and processing services revenues. We own transportation and processing infrastructure that is leased to third parties for throughput fees.Revenue is recognized over time based on the coal tons transported over the beltlines or processed through the facilities. Contract Modifications Contract modifications that impact goods or services or the transaction price are evaluated in accordance with ASC 606. A majority of our contract modificationspertain to our coal and aggregates royalty contracts and include, but are not limited to, extending the lease term, changes to royalty rates, floor prices or minimumconsideration, assignment of the contract or forfeiture of recoupment rights. Consideration received in conjunction with a modification of an ongoing lease will bedeferred and recognized straight-line over the remaining term of the contract. Consideration received to assign a lease to another party and related forfeited minimumswill be recognized immediately upon the termination of the contract. Fees from contract modifications are recognized in lease amendment revenues within royalty andother mineral rights revenues on our Consolidated Statements of Comprehensive Income (Loss) while modifications in royalty rates and minimums will be recognizedprospectively in accordance with the above lease classification. 38Table of Contents Contract Assets and Liabilities from Contracts with Customers Contract assets include receivables from contracts with customers and are recorded when the right to consideration becomes unconditional. Receivables arerecognized when the minimums are contractually owed, production occurs or minimums are accrued for based on the passage of time. Contract liabilities represent minimum consideration received, contractually owed or earned based on the passage of time. The current portion of deferred revenuerelates to deferred revenue on minimum leases and lease amendment fees that are to be recognized as revenue on a straight-line basis over the next twelve months. Thelong-term portion of deferred revenue relates to deferred revenue on production leases and lease amendment fees that are to be recognized as revenue on a straight-linebasis beyond the next twelve months. Due to uncertainty in the amount of deferred revenue that will be recouped and recognized as royalty revenues from productionleases over the next twelve months, we are unable to estimate the current portion of deferred revenue. Equity in Earnings of Sisecam Wyoming. We account for non-marketable equity investments using the equity method of accounting if the investment gives it the ability to exercise significant influenceover, but not control of, an investee. Our 49% investment in Sisecam Wyoming is accounted for using this method. Under the equity method of accounting, investmentsare stated at initial cost and are adjusted for subsequent additional investments and the proportionate share of earnings or losses and distributions. The basis differencebetween the investment and the proportional share of investee's net assets is attributed to net tangible assets and is amortized over its estimated useful life. Thecarrying value in Sisecam Wyoming is recognized in equity in unconsolidated investment on our Consolidated Balance Sheets. Our adjusted share of the earnings orlosses of Sisecam Wyoming and amortization of the basis difference is recognized in equity in earnings of Sisecam Wyoming on the Consolidated Statements ofComprehensive Income (Loss). We decrease our investment for our proportional share of distributions received from Sisecam Wyoming. These cash flows are reportedutilizing the cumulative earnings approach. Under this approach, distributions received are considered returns on investment and classified as operating cash inflowsunless the cumulative distributions received exceed our cumulative equity in earnings. The excess of cumulative distributions received over our cumulative equity inearnings are considered returns of investment and classified as investing cash inflows. Mineral Rights Mineral rights owned and leased are recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. Coal and aggregatesmineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimatedeconomic tonnage as estimated by our internal reserve engineers. The technologies and economic data used by our internal reserve engineers in the estimation of oureconomic tonnage include, but are not limited to, drill logs, geophysical logs, geologic maps including isopach, mine, and coal quality, cross sections, statisticalanalysis, and available public production data. There are numerous uncertainties inherent in estimating the quantities and qualities of economic tonnage, includingmany factors beyond our control. Estimates of economically recoverable tonnage depend upon a number of variable factors and assumptions, any one of which may, ifincorrect, result in an estimate that varies considerably from actual results. Asset Impairment We have developed procedures to evaluate our long-lived assets, including intangible assets, for possible impairment periodically or whenever events or changesin circumstances indicate an asset's net book value may not be recoverable. Potential events or circumstances include, but are not limited to, specific events such as areduction in economically recoverable tons or production ceasing on a property for an extended period. A long-lived asset is deemed impaired when the future expectedundiscounted cash flows from its use and disposition is less than the asset's net book value. Impairment is measured based on the estimated fair value, which is usuallydetermined based upon the present value of the projected future cash flow compared to the asset's net book value. We believe our estimates of cash flows and discountrates are consistent with those of principal market participants. We evaluate our equity investment for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of suchinvestment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fairvalue of the investment to the carrying value of the investment to determine whether impairment has occurred. If the estimated fair value is less than the carrying valueand management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financialstatements as an impairment loss. The fair value of the impaired investment is based on quoted market prices, or upon the present value of expected cash flows usingdiscount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, ifappropriate. Recent Accounting Standards We do not believe that any other recently issued, but not yet effective, accounting standards, if currently adopted, would have a material effect on our financialstatements. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK As a smaller reporting company for the year ended December 31, 2022, we are not required to include this disclosure in our 2022 Form 10-K. 39Table of Contents ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS PageReport of Ernst & Young LLP, Independent Registered Public Accounting Firm (PCAOB ID 42)41Report of BDO USA, LLP, Independent Registered Public Accounting Firm (PCAOB ID 243)43Report of Deloitte & Touche LLP, Independent Registered Public Accounting Firm (PCAOB ID 34)45Consolidated Balance Sheets as of December 31, 2022 and 202146Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2022, 2021 and 202047Consolidated Statements of Partners’ Capital for the years ended December 31, 2022, 2021 and 202048Consolidated Statements of Cash Flows for the years ended December 31, 2022, 2021 and 202049Notes to Consolidated Financial Statements50 40Table of Contents Report of Independent Registered Public Accounting Firm To the Partners of Natural Resource Partners L.P. Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Natural Resource Partners L.P. (the Partnership) as of December 31, 2022 and 2021, the relatedconsolidated statements of comprehensive income (loss), partners’ capital, and cash flows for each of the three years in the period ended December 31, 2022, and therelated notes (collectively referred to as the “consolidated financial statements”). In our opinion, based on our audits and the reports of other auditors, the consolidatedfinancial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2022 and 2021, and the results of its operations and itscash flows for each of the three years in the period ended December 31, 2022, in conformity with U.S. generally accepted accounting principles. We did not audit the financial statements of Sisecam Wyoming LLC (Sisecam Wyoming), a limited liability company in which the Partnership has a 49% interest. In theconsolidated financial statements, the Partnership’s investment in Sisecam Wyoming is stated at $306 million and $276 million as of December 31, 2022 and 2021,respectively, and the Partnership’s equity in the net income of Sisecam Wyoming is stated at $60 million in 2022, $22 million in 2021 and $11 million in 2020. Thosestatements were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for SisecamWyoming, is based solely on the reports of other auditors. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal controlover financial reporting as of December 31, 2022, based on criteria established in Internal Control-Integrated Framework issued by the Committee of SponsoringOrganizations of the Treadway Commission (2013 framework), and our report dated March 2, 2023 expressed an unqualified opinion thereon. Basis for Opinion These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership’s financial statementsbased on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance withthe U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assuranceabout whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks ofmaterial misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures includedexamining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principlesused and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits and the reportof other auditors provide a reasonable basis for our opinion. Critical Audit Matter The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to becommunicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especiallychallenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financialstatements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accountor disclosure to which it relates. 41Table of Contents Impairment Assessment of Mineral Rights Description of the MatterAt December 31, 2022, the Partnership’s mineral rights, net totaled $412 million. As described in Note 2 to theconsolidated financial statements, the Partnership evaluates its long-lived assets (inclusive of mineral rights) forpossible impairment whenever events or changes in circumstances indicate that the carrying amounts of the assetmay not be recoverable (“triggering events”). Management evaluates various qualitative and quantitative factors indetermining whether or not events or changes in circumstances indicate that the carrying amount of an asset may notbe recoverable. Potential events or circumstances include, but are not limited to, reduction in economicallyrecoverable tons or production ceasing on a property for an extended period. Auditing the Partnership’s impairment trigger assessment involved our subjective judgment because, in determiningwhether a triggering event occurred, significant uncertainty exists with judgments management utilizes regarding thelikelihood of future production and the likelihood of potential contract renewals or modifications, which rely oninformation reported by the Partnership’s lessee operators. How We Addressed the Matter in Our AuditWe obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over thePartnership’s impairment assessment process. We tested controls over the Partnership’s process for identifying andevaluating potential triggers of impairment and related significant judgments. To test the Partnership’s impairment assessment, our audit procedures included, among others, making inquiries ofmanagement (including personnel in operations) to understand changes in business, and evaluating the significantjudgments used in the Partnership’s assessment. Specifically, we corroborated reserve information to new reservestudies when available. Additionally, we inspected the termination or significant modification of royalty-based leasecontracts. We searched for and evaluated other publicly available information, such as legislative or regulatorychanges and bankruptcy filings, that corroborates or contradicts management’s assessment. /s/ Ernst & Young LLP We have served as the Partnership’s auditor since 2002. Houston, TexasMarch 2, 2023 42Table of Contents Report of Independent Registered Public Accounting Firm Board of Managers and Members ofSisecam Wyoming LLCAtlanta, Georgia Opinion on the Financial Statements We have audited the accompanying balance sheet of Sisecam Wyoming LLC (the “Company”) as of December 31, 2022, the related statements of operations andcomprehensive income, members' equity, and cash flows for the year then ended, and the related notes (collectively referred to as the “financial statements”). In ouropinion, the financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2022, and the results of its operations andits cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statementsbased on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to beindependent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and ExchangeCommission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America.Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement,whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part ofour audit we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness ofthe Company’s internal control over financial reporting. Accordingly, we express no such opinion. Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performingprocedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financialstatements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overallpresentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion. Critical Audit Matter The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to becommunicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especiallychallenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the financial statements, taken as awhole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures towhich it relates. 43Table of Contents Agreements and Transactions with Affiliates As presented in the financial statements and further as described in Notes 1, 2, 12, and 13 to the financial statements, the Company’s accounts receivable – affiliates,due to affiliates, cost of products sold – affiliates, selling, general and administrative expenses – affiliates account balances were $53,924 thousand, $6,061 thousand,$15,136 thousand, and $19,261 thousand as of and for the year ended December 31, 2022. As the Company is a subsidiary and investee within two different globalgroup structures, agreements directly between the Company and other affiliates, or indirectly between affiliates the Company does not control, can have a significantimpact on recorded amounts or disclosures in the Company's financial statements, including any commitments and contingencies between the Company and affiliates or,potentially, third parties. We identified the completeness and accuracy of the Company's upstream affiliate relationships, transactions, and commitments and contingences originating outside ofSisecam USA and Ciner Enterprises, Inc. group and the impact of such matters on the financial statements as a critical audit matter. Auditing these elements involvedespecially challenging auditor judgement due to the nature and extent of audit effort and knowledge required to address these matters, including the extent of auditprocedures performed to search for completeness, then identify, assess, and test the accuracy of these transactions. The primary procedures we performed to address this critical audit matter included: ●Testing the Company’s affiliate listing for the year ended December 31, 2022, including testing the completeness and accuracy of the Company’s affiliaterelationships, transactions, and commitments and contingencies originating outside of the Sisecam USA and Ciner Enterprises, Inc. group by (i) readingand evaluating publicly available financial filings and news sources related to the Company and its affiliates outside of the Sisecam USA and CinerEnterprises, Inc. group, (ii) inspecting director and executive officer questionnaires from certain of the Company’s directors and officers, (iii) searching thegeneral ledger for transactions with affiliates and for a selection of transactions, tracing to source documents, (iv) considering sources of information thatwere gathered during the audit that could indicate that affiliate relationships, transactions, and commitments and contingencies exist, (v) inquiring ofexecutive officers, key members of management, and certain members of the Board of Directors regarding affiliate relationships, transactions, andcommitments and contingencies, and (vi) confirming with the Company's ultimate parent companies that the affiliate relationships, transactions, andcommitments and contingencies identified and disclosed by the Company were complete and accurate. /s/ BDO USA, LLP We have served as the Company's auditor since 2022. Atlanta, Georgia March 2, 2023 44Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Managers and Members ofSisecam Wyoming LLCAtlanta, Georgia Opinion on the Financial Statements We have audited the accompanying balance sheet of Sisecam Wyoming LLC (the "Company") as of December 31, 2021, the related statements of operations andcomprehensive income, members' equity, and cash flows for each of the two years in the period ended December 31, 2021, and the related notes that are included inExhibit 99.1 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position ofthe Company as of December 31, 2021, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2021, in conformitywith accounting principles generally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statementsbased on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to beindependent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and ExchangeCommission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States ofAmerica. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of materialmisstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financialreporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinionon the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performingprocedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financialstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overallpresentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. /s/ Deloitte & Touche LLP Atlanta, GeorgiaMarch 15, 2022 We began serving as the Company's auditor in 2008. In 2022 we became the predecessor auditor. 45Table of Contents NATURAL RESOURCE PARTNERS L.P.CONSOLIDATED BALANCE SHEETS December 31, (In thousands, except unit data) 2022 2021 ASSETS Current assets Cash and cash equivalents $39,091 $135,520 Accounts receivable, net 42,701 24,538 Other current assets, net 1,822 2,723 Total current assets $83,614 $162,781 Land 24,008 24,008 Mineral rights, net 412,312 437,697 Intangible assets, net 14,713 16,130 Equity in unconsolidated investment 306,470 276,004 Long-term contract receivable, net 28,946 31,371 Other long-term assets, net 7,068 5,832 Total assets $877,131 $953,823 LIABILITIES AND CAPITAL Current liabilities Accounts payable $1,992 $1,956 Accrued liabilities 11,916 10,297 Accrued interest 989 1,213 Current portion of deferred revenue 6,256 11,817 Current portion of long-term debt, net 39,076 39,102 Total current liabilities $60,229 $64,385 Deferred revenue 40,181 50,045 Long-term debt, net 129,205 394,443 Other non-current liabilities 5,472 5,018 Total liabilities $235,087 $513,891 Commitments and contingencies (see Note 15) Class A Convertible Preferred Units (250,000 and 269,321 units issued and outstanding at December 31, 2022 and 2021,respectively, at $1,000 par value per unit; liquidation preference of $1,850 per unit at December 31, 2022 and 2021) (SeeNote 4) $164,587 $183,908 Partners’ capital Common unitholders’ interest (12,505,996 and 12,351,306 units issued and outstanding at December 31, 2022 and2021, respectively) $404,799 $203,062 General partner’s interest 5,977 1,787 Warrant holders’ interest 47,964 47,964 Accumulated other comprehensive income 18,717 3,211 Total partners' capital $477,457 $256,024 Total liabilities and partners' capital $877,131 $953,823 The accompanying notes are an integral part of these consolidated financial statements. 46Table of Contents NATURAL RESOURCE PARTNERS L.P.CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) For the Year Ended December 31, (In thousands, except per unit data) 2022 2021 2020 Revenues and other income Royalty and other mineral rights $307,013 $185,196 $120,166 Transportation and processing services 21,072 9,052 8,845 Equity in earnings of Sisecam Wyoming 59,795 21,871 10,728 Gain on asset sales and disposals 1,082 245 581 Total revenues and other income $388,962 $216,364 $140,320 Operating expenses Operating and maintenance expenses $34,903 $27,049 $24,795 Depreciation, depletion and amortization 22,519 19,075 9,198 General and administrative expenses 21,852 17,360 14,293 Asset impairments 4,457 5,102 135,885 Total operating expenses $83,731 $68,586 $184,171 Income (loss) from operations $305,231 $147,778 $(43,851) Other expenses, net Interest expense, net $(26,274) $(38,876) $(40,968)Loss on extinguishment of debt (10,465) — — Total other expenses, net $(36,739) $(38,876) $(40,968) Net income (loss) $268,492 $108,902 $(84,819)Less: income attributable to preferred unitholders (30,000) (31,609) (30,225)Net income (loss) attributable to common unitholders and the general partner $238,492 $77,293 $(115,044) Net income (loss) attributable to common unitholders $233,722 $75,747 $(112,743)Net income (loss) attributable to the general partner 4,770 1,546 (2,301) Net income (loss) per common unit (see Note 6) Basic $18.72 $6.14 $(9.20)Diluted 13.39 4.81 (9.20) Net income (loss) $268,492 $108,902 $(84,819)Comprehensive income from unconsolidated investment and other 15,506 2,889 2,916 Comprehensive income (loss) $283,998 $111,791 $(81,903) The accompanying notes are an integral part of these consolidated financial statements. 47Table of Contents NATURAL RESOURCE PARTNERS L.P.CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL Accumulated Partners'Capital Other ExcludingNon- Non- Common Unitholders General Warrant Comprehensive Controlling Controlling Total (In thousands) Units Amounts Partner Holders Income (Loss) Interest Interest Capital Balance at December 31, 2019 12,261 $271,471 $3,270 $66,816 $(2,594) $338,963 $(2,935) $336,028 Cumulative effect of adoption ofaccounting standard — (3,833) (78) — — (3,911) — (3,911)Net loss (1) — (83,123) (1,696) — — (84,819) — (84,819)Distributions to common unitholdersand the general partner — (16,552) (338) — — (16,890) — (16,890)Distributions to preferred unitholders — (29,511) (602) — — (30,113) — (30,113)Acquisition of non-controlling interestin BRP — (4,747) (97) — — (4,844) 2,935 (1,909)Unit-based awards amortization andvesting — 3,222 — — — 3,222 — 3,222 Comprehensive income fromunconsolidated investment and other — — — — 2,916 2,916 — 2,916 Balance at December 31, 2020 12,261 $136,927 $459 $66,816 $322 $204,524 $— $204,524 Net income (2) — 106,724 2,178 — — 108,902 — 108,902 Distributions to common unitholdersand the general partner — (22,192) (453) — — (22,645) — (22,645)Distributions to preferred unitholders — (30,519) (623) — — (31,142) — (31,142)Issuance of unit-based awards 90 — — — — — — — Unit-based awards amortization andvesting, net — 2,647 — — — 2,647 — 2,647 Capital contribution — — 32 — — 32 — 32 Warrant settlement — 9,475 194 (18,852) — (9,183) — (9,183)Comprehensive income fromunconsolidated investment and other — — — — 2,889 2,889 — 2,889 Balance at December 31, 2021 12,351 $203,062 $1,787 $47,964 $3,211 $256,024 $— $256,024 Net income (3) — 263,122 5,370 — — 268,492 — 268,492 Distributions to common unitholdersand the general partner — (33,697) (687) — — (34,384) — (34,384)Distributions to preferred unitholders — (29,653) (605) — — (30,258) — (30,258)Issuance of unit-based awards 155 — — — — — — — Unit-based awards amortization andvesting, net — 1,965 — — — 1,965 — 1,965 Capital contribution — — 112 — — 112 — 112 Comprehensive income fromunconsolidated investment and other — — — — 15,506 15,506 — 15,506 Balance at December 31, 2022 12,506 $404,799 $5,977 $47,964 $18,717 $477,457 $— $477,457 (1)Net loss includes $30.2 million of income attributable to preferred unitholders that accumulated during the period, of which $29.6 million is allocated to the common unitholders and$0.6 million is allocated to the general partner. (2)Net income includes $31.6 million of income attributable to preferred unitholders that accumulated during the period, of which $31.0 million is allocated to thecommon unitholders and $0.6 million is allocated to the general partner.(3)Net income includes $30.0 million of income attributable to preferred unitholders that accumulated during the period, of which $29.4 million is allocated to the common unitholdersand $0.6 million is allocated to the general partner. The accompanying notes are an integral part of these consolidated financial statements. 48Table of Contents NATURAL RESOURCE PARTNERS L.P.CONSOLIDATED STATEMENTS OF CASH FLOWS For the Year Ended December 31, (In thousands) 2022 2021 2020 Cash flows from operating activities of continuing operations Net income (loss) $268,492 $108,902 $(84,819)Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization 22,519 19,075 9,198 Distributions from unconsolidated investment 44,835 11,270 14,210 Equity earnings from unconsolidated investment (59,795) (21,871) (10,728)Gain on asset sales and disposals (1,082) (245) (581)Loss on extinguishment of debt 10,465 — — Asset impairments 4,457 5,102 135,885 Bad debt expense 1,062 2,572 4,001 Unit-based compensation expense 5,773 4,039 3,570 Amortization of debt issuance costs and other 2,410 2,265 1,323 Change in operating assets and liabilities: Accounts receivable (18,671) (14,415) 12,853 Accounts payable 37 570 207 Accrued liabilities 935 3,020 (2,205)Accrued interest (224) (501) (602)Deferred revenue (15,424) 307 9,733 Other items, net 1,049 1,714 (4,477)Net cash provided by operating activities of continuing operations $266,838 $121,804 $87,568 Net cash provided by operating activities of discontinued operations — — 1,706 Net cash provided by operating activities $266,838 $121,804 $89,274 Cash flows from investing activities Proceeds from asset sales and disposals $1,083 $249 $623 Return of long-term contract receivable 1,723 2,163 2,122 Acquisition of non-controlling interest in BRP — — (1,000)Capital expenditures (118) — — Net cash provided by investing activities of continuing operations $2,688 $2,412 $1,745 Net cash used in investing activities of discontinued operations — — (65)Net cash provided by investing activities $2,688 $2,412 $1,680 Cash flows from financing activities Debt borrowings $70,000 $— $— Debt repayments (339,396) (39,396) (46,176)Distributions to common unitholders and the general partner (34,384) (22,645) (16,890)Distributions to preferred unitholders (30,000) (15,571) (22,500)Redemption of preferred units paid-in-kind (19,579) — (3,863)Warrant settlement — (9,183) — Acquisition of non-controlling interest in BRP — (1,000) — Contributions from discontinued operations — — 1,641 Other items, net (12,596) (691) — Net cash used in financing activities of continuing operations $(365,955) $(88,486) $(87,788)Net cash used in financing activities of discontinued operations — — (1,641)Net cash used in financing activities $(365,955) $(88,486) $(89,429) Net increase (decrease) in cash and cash equivalents $(96,429) $35,730 $1,525 Cash and cash equivalents of continuing operations at beginning of period 135,520 99,790 98,265 Cash and cash equivalents at end of period $39,091 $135,520 $99,790 Supplemental cash flow information: Cash paid for interest $25,265 $37,378 $39,830 Non-cash investing and financing activities: Plant, equipment, mineral rights and other funded with accounts payable or accruedliabilities $— $— $970 Preferred unit distributions paid-in-kind — 15,571 3,750 The accompanying notes are an integral part of these consolidated financial statements. 49Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Organization and Nature of Operations Natural Resource Partners L.P. (the "Partnership"), a Delaware limited partnership, was formed in April 2002. The general partner of the Partnership is NRP (GP) LP("NRP GP"), a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC, a Delaware limited liability company. The Partnership engagesprincipally in the business of owning, managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal and other naturalresources and owns a non-controlling 49% interest in Sisecam Wyoming LLC ("Sisecam Wyoming"), a trona ore mining and soda ash production business. ThePartnership is organized into two operating segments further described in Note 7. Segment Information. As used in these Notes to Consolidated Financial Statements,the terms "NRP," "we," "us" and "our" refer to Natural Resource Partners L.P. and its subsidiaries, unless otherwise stated or indicated by context. The Partnership’s operations are conducted through, and its operating assets are owned by, its subsidiaries. The Partnership owns its subsidiaries through onewholly owned operating company, NRP (Operating) LLC ("Opco"). NRP GP has sole responsibility for conducting the Partnership's business and for managing itsoperations. Because NRP GP is a limited partnership, its general partner, GP Natural Resource Partners LLC, conducts its business and operations, and the board ofdirectors and officers of GP Natural Resource Partners LLC makes decisions on its behalf. Robertson Coal Management LLC ("RCM"), a limited liability company whollyowned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. Subject to the Board Representation and ObservationRights Agreement with certain entities controlled by funds affiliated with Blackstone Inc. (collectively referred to as "Blackstone") and affiliates of GoldenTree AssetManagement LP (collectively referred to as "GoldenTree"), RCM is entitled to appoint the directors of the Board of Directors of GP Natural Resource Partners LLC (the"Board of Directors"). RCM has delegated the right to appoint one director to Blackstone. 2. Summary of Significant Accounting Policies Basis of Presentation The accompanying Consolidated Financial Statements of the Partnership have been prepared in accordance with generally accepted accounting principles in theUnited States of America ("GAAP"). The Consolidated Financial Statements include the accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries.The Partnership has an equity investment in Sisecam Wyoming through which it is able to exercise significant influence over but does not control the investee and isnot the primary beneficiary of the investee’s activities and is accounted for using the equity method. Intercompany transactions and balances have been eliminated.Reclassifications have been made to prior year amounts in the Consolidated Financial Statements to conform with current year presentation. These reclassifications hadno impact on previously reported total assets, total liabilities, partners' capital, net income (loss) or cash flows from operating, investing or financing activities. Use of Estimates Preparation of the accompanying financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reportedamounts of assets and liabilities on the accompanying Consolidated Balance Sheets, the disclosure of contingent assets and liabilities at the date of the financialstatements, and the reported amounts of revenues and expenses on the accompanying Consolidated Statements of Comprehensive Income (Loss) during the reportingperiod. Actual results could differ from those estimates. The most significant estimates pertain to coal and aggregates mineral rights and related cash flow estimateswhich are used to compute depreciation, depletion and amortization and impairments of coal and aggregates properties and related intangible assets and commitmentsand contingencies. Fair Value The Partnership discloses certain assets and liabilities using fair value as defined by authoritative guidance. Fair value is defined as the price that would bereceived to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. See Note 12. Fair ValueMeasurements for further details. There are three levels of inputs that may be used to measure fair value:•Level 1—Quoted prices in active markets for identical assets or liabilities.•Level 2—Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or otherinputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.•Level 3—Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. Level 3 assets andliabilities include financial assets and liabilities whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as wellas instruments for which the determination of fair value requires significant management judgment or estimation. 50Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED Cash and Cash Equivalents The Partnership considers all highly liquid short-term investments with an original maturity of three months or less to be cash equivalents. Allowance for Doubtful Accounts The Partnership records an allowance for doubtful accounts for its accounts receivable and notes receivable comprised of estimated credit risk and non-credit risk(e.g., legal disputes) losses. Receivables are written off when collection efforts are exhausted and future recovery is doubtful. The Partnership includes an allowance forcurrent expected credit losses ("CECL") on its financial assets based on the loss-rate method. NRP assesses the likelihood of collection of its receivables utilizinghistorical loss rates, current market conditions that include the estimated impact of the global COVID-19 pandemic, industry and macroeconomic factors, reasonable andsupportable forecasts and facts or circumstances of individual customers and properties. See Note 18. Credit Losses for more information. The total allowance related toaccounts receivables included in accounts receivables, net on the Partnership's Consolidated Balance Sheets was $4.5 million and $3.2 million at December 31, 2022 and2021, respectively. The total allowance related to short-term notes receivables included in other current assets, net on the Partnership's Consolidated Balance Sheetswas $0.0 million and $0.1 million at December 31, 2022 and 2021, respectively. The total allowance related to the Partnership's long-term financing receivable included inlong-term contract receivable, net on the Consolidated Balance Sheets was $1.0 million and $1.1 million at December 31, 2022 and 2021, respectively. The Partnershiprecorded bad debt expense of $1.1 million, $2.6 million and $4.0 million included in operating and maintenance expenses on its Consolidated Statements ofComprehensive Income (Loss) for the year ended December 31, 2022, 2021 and 2020, respectively. Mineral Rights Mineral rights owned and leased are recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. Coal and aggregatesmineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimatedeconomic tonnage therein. Intangible Assets The Partnership’s intangible assets consist of mineral royalty and transportation contracts that at acquisition were more favorable for the Partnership thanprevailing market rates, known as above-market contracts. The estimated fair value of the above-market rate contracts are determined based on the present value offuture cash flow projections related to the underlying assets acquired. Intangible assets are amortized on a unit-of-production basis by asset based upon minerals minedor transported in relation to the net book value of the intangible asset and estimated economic tonnage expected to be mined or transported during the above-marketcontract term. Asset Impairment The Partnership has developed procedures to evaluate its long-lived assets, including intangible assets, for possible impairment periodically or whenever eventsor changes in circumstances indicate an asset's net book value may not be recoverable. Potential events or circumstances include, but are not limited to, specific eventssuch as a reduction in economically recoverable tons or production ceasing on a property for an extended period. This analysis is based on historic, current and futureperformance and considers both quantitative and qualitative information. A long-lived asset is deemed impaired when the future expected undiscounted cash flows fromits use and disposition is less than the asset's net book value. Impairment is measured based on the estimated fair value, which is usually determined based upon thepresent value of the projected future cash flows compared to the asset's net book value. The Partnership believes its estimates of cash flows and discount rates areconsistent with those of principal market participants. The Partnership evaluates its equity investment for impairment when events or changes in circumstances indicate, in management’s judgment, that the carryingvalue of such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares theestimated fair value of the investment to the carrying value of the investment to determine whether potential impairment has occurred. If the estimated fair value is lessthan the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value isrecognized in the financial statements as an impairment loss. The fair value of the impaired investment is based on quoted market prices (Level 1), or upon the presentvalue of expected cash flows using discount rates believed to be consistent with those used by principal market participants (Level 3), plus market analysis ofcomparable assets owned by the investee, if appropriate (Level 3). Accrued Liabilities Included in accrued liabilities on the Partnership's Consolidated Balance Sheets at December 31, 2022 were $9.5 million of accrued employee costs and $2.4 millionof other accrued liabilities. These amounts were $7.7 million and $2.6 million of accrued employee costs and other accrued liabilities, respectively, at December 31, 2021.Other accrued liabilities at both December 31, 2022 and 2021 included property taxes. 51Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED Revenue Recognition Mineral Rights Segment Revenues Royalty-based leases. Approximately two-thirds of the Partnership's royalty-based leases have initial terms of five to 40 years, with substantially all lesseeshaving the option to extend the lease for additional terms. For these types of leases, the lessees generally make payments to NRP based on the greater of a percentage ofthe gross sales price or a fixed price per ton of mineral mined and sold. Most of NRP’s coal and aggregates royalty leases require the lessee to pay quarterly or annualminimum amounts, either made in advance or arrears, which are generally recoupable through actual royalty production over certain time periods that generally rangefrom three to five years. The Partnership has defined its coal and aggregates royalty lease performance obligation as providing the lessee the right to mine and sell its coal or aggregatesover the lease term. NRP then evaluated the likelihood that consideration it expected to receive from its lessees resulting from production would exceed considerationexpected to be received from minimum payments over the lease term. As a result of this evaluation, revenue recognition from the Partnership's royalty-based leases is based on either production or minimum payments as follows:•Production Leases: Leases for which the Partnership expects that consideration from production will be greater than consideration from minimums over the leaseterm. Revenue for these leases is recognized over time based on production as royalty revenues, as applicable. Deferred revenue from minimums is recognized asroyalty revenues when recoupment occurs or as production lease minimum revenues when the recoupment period expires. In addition, NRP recognizes breakagerevenue from minimums when NRP determines that recoupment is remote. This breakage revenue is included in production lease minimum revenues.•Minimum Leases: Leases for which the Partnership expects that consideration from minimums will be greater than consideration from production over the leaseterm. Revenue for these leases is recognized straight-line over the lease term based on the minimum consideration amount as minimum lease straight-line revenues. This evaluation is performed at the inception of the lease and only reassessed upon modification or renewal of the lease. Oil and gas related revenues consist of revenues from royalties and overriding royalties and are recognized on the basis of volume of hydrocarbons sold bylessees and the corresponding revenues from those sales. Also, included within oil and gas royalty revenues are lease bonus payments, which are generally paid uponthe execution of a lease. The Partnership also has overriding royalty revenue interests in certain coal and aggregates mineral rights. Revenue from these interests isrecognized over time based on when the coal is sold. Carbon neutral initiatives. Revenues related to consideration for carbon neutral initiatives that are recognized at a point in time upon satisfaction of NRP'sperformance obligation. Wheelage revenues. Revenues related to fees collected per ton to transport foreign coal across property owned by the Partnership that is recognized over time astransportation across the property occurs. Other revenues. Other revenues consist primarily of rental payments and surface damage fees related to certain land owned by the Partnership and are recognizedstraight-line over time as it is earned. Other revenues also include property tax revenues. The majority of property taxes paid on the Partnership's properties arereimbursable by the lessee and are recognized on a gross basis over time which reflects the reimbursement of property taxes by the lessee. Property taxes paid by NRPare included in operating and maintenance expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss). Transportation and processing services revenues. The Partnership owns transportation and processing infrastructure that is leased to third parties for throughputfees. Revenue is recognized over time based on the coal tons transported over the beltlines or processed through the facilities. Contract Modifications Contract modifications that impact goods or services or the transaction price are evaluated in accordance with ASC 606. A majority of the Partnership's contractmodifications pertain to its coal and aggregates royalty contracts and include, but are not limited to, extending the lease term, changes to royalty rates, floor prices orminimum consideration, assignment of the contract or forfeiture of recoupment rights. Consideration received in conjunction with a modification of an ongoing lease willbe deferred and recognized straight-line over the remaining term of the contract. Consideration received to assign a lease to another party and related forfeited minimumswill be recognized immediately upon the termination of the contract. Fees from contract modifications are recognized in lease amendment revenues within royalty andother mineral rights revenues on the Consolidated Statements of Comprehensive Income (Loss) while modifications in royalty rates and minimums will be recognizedprospectively in accordance with the above lease classification. Contract Assets and Liabilities from Contracts with Customers Contract assets include receivables from contracts with customers and are recorded when the right to consideration becomes unconditional. Receivables arerecognized when the minimums are contractually owed, production occurs or minimums accrued for based on the passage of time. Contract liabilities represent minimum consideration received, contractually owed or earned based on the passage of time. The current portion of deferred revenuerelates to deferred revenue on minimum leases and lease amendment fees that are to be recognized as revenue on a straight-line basis over the next twelve months. Thelong-term portion of deferred revenue relates to deferred revenue on production leases and lease amendment fees that are to be recognized as revenue on a straight-linebasis beyond the next twelve months. Due to uncertainty in the amount of deferred revenue that will be recouped and recognized as coal royalty revenues from itsproduction leases over the next twelve months, the Partnership is unable to estimate the current portion of deferred revenue. 52Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED Equity in Earnings of Sisecam Wyoming The Partnership accounts for non-marketable equity investments using the equity method of accounting if the investment gives it the ability to exercisesignificant influence over, but not control of, an investee. The Partnership's 49% investment in Sisecam Wyoming is accounted for using this method. Under the equitymethod of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and the proportionate share of earnings or lossesand distributions. The basis difference between the investment and the proportional share of investee's net assets is attributed to net tangible assets and is amortizedover its estimated useful life. The carrying value in Sisecam Wyoming is recognized in equity in unconsolidated investment on the Partnership's Consolidated BalanceSheets. The Partnership's adjusted share of the earnings or losses of Sisecam Wyoming and amortization of the basis difference is recognized in equity in earnings ofSisecam Wyoming on the Consolidated Statements of Comprehensive Income (Loss). The Partnership decreases its investment for its proportional share of distributionsreceived from Sisecam Wyoming. These cash flows are reported utilizing the cumulative earnings approach. Under this approach, distributions received are consideredreturns on investment and classified as operating cash inflows unless the cumulative distributions received exceed the Partnership's cumulative equity in earnings. Theexcess of cumulative distributions received over the Partnership's cumulative equity in earnings are considered returns of investment and classified as investing cashinflows. Property Taxes The Partnership is responsible for paying property taxes on the properties it owns. Typically, the lessees are contractually responsible for reimbursing thePartnership for property taxes on the leased properties. The payment of and reimbursement of property taxes is included in operating and maintenance expenses and inroyalty and other mineral rights revenues, respectively, on the Consolidated Statements of Comprehensive Income (Loss). Unit-Based Compensation The Partnership has awarded unit-based compensation in the form of equity-based awards and phantom units. Compensation cost is measured at the grant datefor equity-classified awards and remeasured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the serviceperiod, which is generally the vesting period. Forfeitures are recognized as they occur. Unit-based compensation expense for all awards is recognized in general andadministrative expenses and operating and maintenance expenses on the Consolidated Statements of Comprehensive Income (Loss). See Note 16. Unit-BasedCompensation for more information. Deferred Financing Costs Deferred financing costs consist of legal and other costs related to the issuance of the Partnership’s debt. These costs are amortized over the term of therespective line-of-credit or debt arrangements. Deferred financing costs related to the Partnership's revolving credit facility are included in other long-term assets, net onthe Partnership's Consolidated Balance Sheets. Deferred financing costs related to the Partnership's note agreements are included as a direct deduction from thecarrying amount of the debt liability in current portion of long-term debt, net or long-term debt, net on the Partnership's Consolidated Balance Sheets. Income Taxes The Partnership is not subject to federal or material state income taxes as the unitholders are taxed individually on their allocable share of taxable income. Netincome (loss) for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis andfinancial reporting basis of assets and liabilities. In the event of an examination of the Partnership’s tax return, the tax liability of the unitholders could be changed if anadjustment in the Partnership’s income is ultimately sustained by the taxing authorities. 53Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 3. Revenues from Contracts with Customers The following table represents the Partnership's Mineral Rights segment revenues by major source: For the Year Ended December 31, (In thousands) 2022 2021 2020 Coal royalty revenues $226,956 $104,089 $51,868 Production lease minimum revenues 5,854 14,269 21,749 Minimum lease straight-line revenues 18,792 20,564 16,796 Carbon neutral initiative revenues 8,600 13,790 — Property tax revenues 5,878 6,028 5,786 Wheelage revenues 13,961 10,065 7,025 Coal overriding royalty revenues 3,434 4,367 4,977 Lease amendment revenues 3,201 4,696 3,450 Aggregates royalty revenues 3,299 1,889 1,717 Oil and gas royalty revenues 16,161 4,506 5,816 Other revenues 877 933 982 Royalty and other mineral rights revenues $307,013 $185,196 $120,166 Transportation and processing services revenues (1) 21,072 9,052 8,845 Total Mineral Rights segment revenues $328,085 $194,248 $129,011 (1)Transportation and processing services revenues from contracts with customers as defined under ASC 606 was $17.9 million, $5.4 million and $5.0 million for theyear ended December 31, 2022, 2021 and 2020, respectively. The remaining transportation and processing services revenues of $3.2 million, $3.6 million and$3.8 million for the year ended December 31, 2022, 2021 and 2020, respectively, related to other NRP-owned infrastructure leased to and operated by third-partyoperators accounted for under other guidance. See Note 17. Financing Transaction for more information. The following table details the Partnership's Mineral Rights segment receivables and liabilities resulting from contracts with customers: December 31, (In thousands) 2022 2021 Receivables Accounts receivable, net $39,004 $22,277 Other current assets, net (1) — 769 Other long-term assets, net (2) 75 250 Contract liabilities Current portion of deferred revenue $6,256 $11,817 Deferred revenue 40,181 50,045 (1)Other current assets, net includes short-term notes receivables from contracts with customers.(2)Other long-term assets, net includes long-term lease amendment fee receivables from contracts with customers. The following table shows the activity related to the Partnership's Mineral Rights segment deferred revenue: For the Year Ended December 31, (In thousands) 2022 2021 2020 Balance at beginning of period (current and non-current) $61,862 $61,554 $51,821 Increase due to minimums and lease amendment fees 19,073 19,842 41,557 Recognition of previously deferred revenue (34,498) (19,534) (31,824)Balance at end of period (current and non-current) $46,437 $61,862 $61,554 The Partnership's non-cancelable annual minimum payments due under the lease terms of its coal and aggregates royalty and overriding royalty leases are asfollows as of December 31, 2022 (in thousands): Lease Term (1) Weighted Average RemainingYears Annual MinimumPayments 0 - 5 years 2.2 $21,981 5 - 10 years 3.6 7,517 10+ years 12.7 27,221 Total 7.4 $56,719 (1)Lease term does not include renewal periods. 54Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 4. Class A Convertible Preferred Units and Warrants On March 2, 2017, NRP issued $250 million of Class A Convertible Preferred Units representing limited partner interests in NRP (the "preferred units") to certainentities controlled by funds affiliated with The Blackstone Group Inc. (collectively referred to as "Blackstone") and certain affiliates of GoldenTree Asset ManagementLP (collectively referred to as "GoldenTree") (together the "preferred purchasers") pursuant to a Preferred Unit and Warrant Purchase Agreement. NRP issued 250,000preferred units to the preferred purchasers at a price of $1,000 per preferred unit (the "per unit purchase price"), less a 2.5% structuring and origination fee. The preferredunits entitle the preferred purchasers to receive cumulative distributions at a rate of 12% of the purchase price per year, up to one half of which NRP may pay inadditional preferred units (such additional preferred units, the "PIK units"). The preferred units have a perpetual term, unless converted or redeemed as described below. NRP also issued two tranches of warrants (the "warrants") to purchase common units to the preferred purchasers (warrants to purchase 1.75 million common unitswith a strike price of $22.81 and warrants to purchase 2.25 million common units with a strike price of $34.00). The warrants may be exercised by the holders thereof atany time before the eighth anniversary of the closing date. Upon exercise of the warrants, NRP may, at its option, elect to settle the warrants in common units or cash,each on a net basis. After March 2, 2022 and prior to March 2, 2025, the holders of the preferred units may elect to convert up to 33% of the outstanding preferred units in any 12-month period into common units if the volume weighted average trading price of our common units (the "VWAP") for the 30 trading days immediately prior to datenotice is provided is greater than $51.00. In such case, the number of common units to be issued upon conversion would be equal to the per unit purchase price plus thevalue of any accrued and unpaid distributions divided by an amount equal to a 7.5% discount to the VWAP for the 30 trading days immediately prior to the notice ofconversion. Rather than have the preferred units convert to common units in accordance with the provisions of this paragraph, NRP would have the option to elect toredeem the preferred units proposed to be converted for cash at a price equal to the per unit purchase price plus the value of any accrued and unpaid distributions. On or after March 2, 2025, the holders of the preferred units may elect to convert the preferred units to common units at a conversion rate equal to the LiquidationValue divided by an amount equal to a 10% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion. The “liquidation value” will bean amount equal to the greater of: (1) (a) the per unit purchase price multiplied by (i) prior to March 2, 2020, 1.50, (ii) on or after March 2, 2020 and prior to March 2, 2021,1.70 and (iii) on or after March 2, 2021, 1.85, less (b)(i) all preferred unit distributions previously made by NRP and (ii) all cash payments previously made in respect ofredemption of any PIK units; and (2) the per unit purchase price plus the value of all accrued and unpaid distributions. To the extent the holders of the preferred units have not elected to convert their preferred units before March 2, 2029, NRP has the right to force conversion of thepreferred units at a price equal to the liquidation value divided by an amount equal to a 10% discount to the VWAP for the 30 trading days immediately prior to thenotice of conversion. In addition, NRP has the ability to redeem at any time (subject to compliance with its debt agreements) all or any portion of the preferred units and any outstandingPIK units for cash. The redemption price for each outstanding PIK unit is $1,000 plus the value of any accrued and unpaid distributions per PIK unit. The redemptionprice for each preferred unit is the liquidation value divided by the number of outstanding preferred units. The preferred units are redeemable at the option of thepreferred purchasers only upon a change in control. The terms of the preferred units contain certain restrictions on NRP's ability to pay distributions on its common units. To the extent that either (i) NRP'sconsolidated Leverage Ratio, as defined in the Partnership's Fifth Amended and Restated Partnership Agreement dated March 2, 2017 (the "restated partnershipagreement"), is greater than 3.25x, or (ii) the ratio of NRP's Distributable Cash Flow (as defined in the Restated Partnership Agreement) to cash distributions made orproposed to be made is less than 1.2x (in each case, with respect to the most recently completed four-quarter period), NRP may not increase the quarterly distributionabove $0.45 per quarter without the approval of the holders of a majority of the outstanding preferred units. In addition, if at any time after January 1, 2022, any PIK unitsare outstanding, NRP may not make distributions on its common units until it has redeemed all PIK units for cash. The holders of the preferred units have the right to vote with holders of NRP’s common units on an as-converted basis and have other customary approval rightswith respect to changes of the terms of the preferred units. In addition, Blackstone has certain approval rights over certain matters as identified in the restatedpartnership agreement. GoldenTree also has more limited approval rights that will expand once Blackstone's ownership goes below the minimum preferred unit threshold(as defined below). These approval rights are not transferrable without NRP's consent. In addition, the approval rights held by Blackstone and GoldenTree will terminateat such time that Blackstone (together with their affiliates) or GoldenTree (together with their affiliates), as applicable, no longer own at least 20% of the total number ofpreferred units issued on the closing date, together with all PIK units that have been issued but not redeemed (the "minimum preferred unit threshold"). At the closing, pursuant to the Board Representation and Observation Rights Agreement, the Preferred Purchasers received certain board appointment andobservation rights, and Blackstone appointed one director and one observer to the Board of Directors. NRP also entered into a registration rights agreement (the "preferred unit and warrant registration rights agreement") with the preferred purchasers, pursuant towhich NRP is required to file (i) a shelf registration statement to register the common units issuable upon exercise of the warrants and to cause such registrationstatement to become effective not later than 90 days following the closing date and (ii) a shelf registration statement to register the common units issuable uponconversion of the preferred units and to cause such registration statement to become effective not later than the earlier of the fifth anniversary of the closing date or 90days following the first issuance of any common units upon conversion of preferred units (the "registration deadlines"). In addition, the preferred unit and warrantregistration rights agreement gives the preferred purchasers piggyback registration and demand underwritten offering rights under certain circumstances. The shelfregistration statement to register the common units issuable upon exercise of the warrants became effective on April 20, 2017. If the shelf registration statement toregister the common units issuable upon conversion of the preferred units is not effective by the applicable registration deadline, NRP will be required to pay thepreferred purchasers liquidated damages in the amounts and upon the term set forth in the preferred unit and warrant registration rights agreement. 55Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED Accounting for the Preferred Units and Warrants Classification The preferred units are accounted for as temporary equity on NRP's Consolidated Balance Sheets due to certain contingent redemption rights that may beexercised at the election of preferred purchasers. The warrants are accounted for as equity on NRP's Consolidated Balance Sheets. Initial Measurement The net transaction price was allocated to the preferred units and warrants based on their relative fair values at inception date. NRP allocated the transactionissuance costs to the preferred units and warrants primarily on a pro-rata basis based on their relative inception date allocated values. Subsequent Measurement Subsequent adjustment of the preferred units will not occur until NRP has determined that the conversion or redemption of all or a portion of the preferred units isprobable of occurring. Once conversion or redemption becomes probable of occurring, the carrying amount of the preferred units will be accreted to their redemptionvalue over the period from the date the feature is probable of occurring to the date the preferred units can first be converted or redeemed. Activity related to the preferred units is as follows: Units Financial (In thousands, except unit data) Outstanding Position Balance at December 31, 2019 250,000 $164,587 Distribution paid-in-kind 3,750 3,750 Balance at December 31, 2020 253,750 $168,337 Distribution paid-in-kind 15,571 15,571 Balance at December 31, 2021 269,321 $183,908 Redemption of preferred units paid-in-kind (19,321) (19,321)Balance at December 31, 2022 250,000 $164,587 In February 2023, the Partnership received a notice from holders of the Class A Preferred Units exercising their right to either convert or redeem, at the election ofNRP, an aggregate of 47,499 Class A Preferred Units. The Partnership chose to redeem the preferred units for $47.5 million in cash plus any accrued and unpaiddistributions, utilizing cash on hand and borrowings under the Opco Credit Facility. Of the originally issued 250,000 Class A Preferred Units, 202,501 Class A PreferredUnits remain outstanding as of the date of this report. The 30-day VWAP ending on the business day prior to the redemption was $51.01. Subsequent adjustment of the warrants will not occur until the warrants are exercised, at which time, NRP may, at its option, elect to settle the warrants in commonunits or cash, each on a net basis. The net basis will be equal to the difference between the Partnership's common unit price and the strike price of the warrant. Oncewarrant exercise occurs, the difference between the carrying amount of the warrants and the net settlement amount will be allocated on a pro-rata basis to the commonunitholders and general partner. On November 10, 2021 (the "exercise date"), Blackstone exercised all of its 997,500 warrants with a strike price of $22.81 and NRP settled the warrants in cash on anet basis. NRP delivered the net cash settlement amount of $9.2 million. The 15-day VWAP ending on the business day prior to the exercise date was $32.02. Activity related to the warrants is as follows: Warrants Financial (In thousands, except warrant data) Outstanding Position Balance at December 31, 2019 and 2020 4,000,000 $66,816 Warrant settlement (997,500) (18,852)Balance at December 31, 2021 and 2022 3,002,500 $47,964 Certain embedded features within the preferred unit and warrant purchase agreement are accounted for at fair value and are remeasured each quarter. See Note 12.Fair Value Measurements for further information regarding valuation of these embedded derivatives. 56Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 5. Common and Preferred Unit Distributions The Partnership makes distributions to common and preferred unitholders on a quarterly basis, subject to approval by the Board of Directors. NRP recognizes bothcommon unit and preferred unit distributions on the date the distribution is declared. Distributions made on the common units and the general partner's general partner ("GP") interest are made on a pro-rata basis in accordance with their relativepercentage interests in the Partnership. The general partner is entitled to receive 2% of such distributions. Income (loss) available to common unitholders and the general partner is adjusted by preferred unit distributions that accumulated during the period. NRP adjustednet income (loss) available to common unitholders and the general partner by $30.0 million, $31.6 million and $30.2 million during the year ended December 31, 2022, 2021and 2020, respectively as a result of accumulated preferred unit distributions earned during the period. The following table shows the distributions declared and paid to common and preferred unitholders during the year ended December 31, 2022, 2021 and 2020,respectively: Cash Distributions Paid-in-kindDistributions Common Units Preferred Units Total Total Total Distribution Distribution(1) Distribution Distribution Distribution Date Paid Period Covered by Distribution per Unit (In thousands) per Unit (In thousands) (In units) 2022 February 2022 October 1 - December 31, 2021 $0.45 $5,672 $30.00 $7,500 — February 2022 (2) July 1 2020 - September 30, 2021 — — 78.31 19,579 — May 2022 January 1 - March 31, 2022 0.75 9,570 30.00 7,500 — August 2022 April 1 - June 30, 2022 0.75 9,571 30.00 7,500 — November 2022 July 1 - September 30, 2022 0.75 9,571 30.00 7,500 — 2021 February 2021 October 1 - December 31, 2020 $0.45 $5,630 $15.00 $3,806 3,806 May 2021 January 1 - March 31, 2021 0.45 5,672 15.00 3,864 3,864 August 2021 April 1 - June 30, 2021 0.45 5,671 15.00 3,921 3,921 November 2021 July 1 - September 30, 2021 0.45 5,672 15.00 3,980 3,980 2020 February 2020 October 1 - December 31, 2019 $0.45 $5,630 $30.00 $7,500 — May 2020 January 1 - March 31, 2020 — — 15.00 3,750 3,750 June 2020 (2) January 1 - March 31, 2020 — — 15.45 3,863 — August 2020 April 1 - June 30, 2020 0.45 5,630 30.00 7,500 — November 2020 July 1 - September 30, 2020 0.45 5,630 15.00 3,750 3,750 (1)Total common unit distribution includes the amount paid to NRP's general partner in accordance with the general partner's 2% general partner interest.(2)Redemption of preferred units paid in kind plus accrued interest. 57Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 6. Net Income (Loss) Per Common Unit Basic net income (loss) per common unit is computed by dividing net income (loss), after considering income attributable to preferred unitholders and the generalpartner’s general partner interest, by the weighted average number of common units outstanding. Diluted net income (loss) per common unit includes the effect of NRP'spreferred units, warrants, and unvested unit-based awards if the inclusion of these items is dilutive. The dilutive effect of the preferred units is calculated using the if-converted method. Under the if-converted method, the preferred units are assumed to beconverted at the beginning of the period, and the resulting common units are included in the denominator of the diluted net income (loss) per unit calculation for theperiod being presented. Distributions declared in the period and undeclared distributions on the preferred units that accumulated during the period are added back tothe numerator for purposes of the if-converted calculation. The calculation of diluted net income per common unit for the year ended December 31, 2022 and 2021includes the assumed conversion of the preferred units. The calculation of diluted net loss per common unit for the years ended December 31, 2020 does not include theassumed conversion of the preferred units because the impact would have been anti-dilutive. The dilutive effect of the warrants is calculated using the treasury stock method, which assumes that the proceeds from the exercise of these instruments are usedto purchase common units at the average market price for the period. The calculation of diluted net income per common unit for the year ended December 31,2022 includes the net settlement of warrants to purchase 0.75 million common units with a strike price of $22.81 and the net settlement of warrants to purchase2.25 million common units with a strike price of $34.00.The calculation of diluted net income per common unit for the year ended December 31, 2021 includes the netsettlement of warrants to purchase 0.75 million common units with a strike price of $22.81 but does not include the net settlement of warrants to purchase 2.25 millioncommon units with a strike price of $34.00 because the impact would have been anti-dilutive. The calculation of diluted net loss per common unit for the year endedDecember 31, 2020 does not include the net settlement of warrants to purchase 1.75 million common units with a strike price of $22.81 or the net settlement of warrants topurchase 2.25 million common units with a strike price of $34.00 because the impact would have been anti-dilutive. The following table reconciles the numerators and denominators of the basic and diluted net income (loss) per common unit computations and calculates basic anddiluted net income (loss) per common unit: For the Year Ended December 31, (In thousands, except per unit data) 2022 2021 2020 Allocation of net income (loss) Net income (loss) $268,492 $108,902 $(84,819)Less: income attributable to preferred unitholders (30,000) (31,609) (30,225)Net income (loss) attributable to common unitholders and the general partner $238,492 $77,293 $(115,044)Add (less): net loss (income) attributable to the general partner (4,770) (1,546) 2,301 Net income (loss) attributable to common unitholders $233,722 $75,747 $(112,743) Basic net income (loss) per common unit Weighted average common units—basic 12,484 12,337 12,261 Basic net income (loss) per common unit $18.72 $6.14 $(9.20) Diluted net income (loss) per common unit Weighted average common units—basic 12,484 12,337 12,261 Plus: dilutive effect of preferred units 6,176 9,604 — Plus: dilutive effect of warrants 783 74 — Plus: dilutive effect of unvested unit-based awards 210 178 — Weighted average common units—diluted 19,653 22,193 12,261 Net income (loss) $268,492 $108,902 $(84,819)Less: income attributable to preferred unitholders — — (30,225)Diluted net income (loss) attributable to common unitholders and the general partner $268,492 $108,902 $(115,044)Add (less): diluted net loss (income) attributable to the general partner (5,370) (2,178) 2,301 Diluted net income (loss) attributable to common unitholders $263,122 $106,724 $(112,743) Diluted net income (loss) per common unit $13.39 $4.81 $(9.20) 58Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 7. Segment Information The Partnership's segments are strategic business units that offer distinct products and services to different customers in different geographies within the U.S.and that are managed accordingly. NRP has the following two operating segments: Mineral Rights—consists of mineral interests and other subsurface rights across the United States. NRP's ownership provides critical inputs for themanufacturing of steel, electricity and basic building materials, as well as opportunities for carbon sequestration and renewable energy. The Partnership is working tostrategically redefine its business as a key player in the transitional energy economy in the years to come. Soda Ash—consists of the Partnership's 49% non-controlling equity interest in Sisecam Wyoming, a trona ore mining operation and soda ash refinery in the GreenRiver Basin of Wyoming. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into the glass and chemicalsindustries. Direct segment costs and certain other costs incurred at the corporate level that are identifiable and that benefit the Partnership's segments are allocated to theoperating segments accordingly. These allocated costs generally include salaries and benefits, insurance, property taxes, legal, royalty, information technology andshared facilities services and are included in operating and maintenance expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss). Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these departments include interest andfinancing, corporate headquarters and overhead, centralized treasury, legal and accounting and other corporate-level activity not specifically allocated to a segment andare included in general and administrative expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss). The following table summarizes certain financial information for each of the Partnership's business segments: Operating Segments (In thousands) Mineral Rights Soda Ash Corporate andFinancing Total For the Year Ended December 31, 2022 Revenues $328,085 $59,795 $— $387,880 Gain on asset sales and disposals 1,082 — — 1,082 Operating and maintenance expenses 34,743 160 — 34,903 Depreciation, depletion and amortization 22,519 — — 22,519 General and administrative expenses — — 21,852 21,852 Asset impairments 4,457 — — 4,457 Other expenses, net — — 36,739 36,739 Net income (loss) 267,448 59,635 (58,591) 268,492 As of December 31, 2022 Total assets $566,615 $306,470 $4,046 $877,131 For the Year Ended December 31, 2021 Revenues $194,248 $21,871 $— $216,119 Gain on asset sales and disposals 245 — — 245 Operating and maintenance expenses 26,880 169 — 27,049 Depreciation, depletion and amortization 19,075 — — 19,075 General and administrative expenses — — 17,360 17,360 Asset impairments 5,102 — — 5,102 Other expenses, net 24 — 38,852 38,876 Net income (loss) 143,412 21,702 (56,212) 108,902 As of December 31, 2021 Total assets $675,579 $276,004 $2,240 $953,823 For the Year Ended December 31, 2020 Revenues $129,011 $10,728 $— $139,739 Gain on asset sales and disposals 581 — — 581 Operating and maintenance expenses 24,610 185 — 24,795 Depreciation, depletion and amortization 9,198 — — 9,198 General and administrative expenses — — 14,293 14,293 Asset impairments 135,885 — — 135,885 Other expenses, net 79 — 40,889 40,968 Net income (loss) (40,180) 10,543 (55,182) (84,819) 59Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 8. Equity Investment The Partnership accounts for its 49% investment in Sisecam Wyoming using the equity method of accounting. Activity related to this investment is as follows: For the Year Ended December 31, (In thousands) 2022 2021 2020 Balance at beginning of period $276,004 $262,514 $263,080 Income allocation to NRP’s equity interests (1) 64,712 26,979 15,205 Amortization of basis difference (4,917) (5,108) (4,477)Other comprehensive income 15,506 2,889 2,916 Distribution (44,835) (11,270) (14,210)Balance at end of period $306,470 $276,004 $262,514 (1)Amounts reclassified into income out of accumulated other comprehensive income (loss) were ($6.8 million), $0.0 million and $1.7 million for the year endedDecember 31, 2022, 2021 and 2020, respectively. The difference between the amount at which the investment in Sisecam Wyoming is carried and the amount of underlying equity in Sisecam Wyoming's net assetswas $121.3 million and $126.3 million as of December 31, 2022 and 2021, respectively. This excess basis relates to property, plant and equipment and right to mine assets.The excess basis difference that relates to property, plant and equipment is being amortized into income using the straight-line method over 27 years. The excess basisdifference that relates to right to mine assets is being amortized into income using the units of production method. The following table represents summarized financial information for Sisecam Wyoming as derived from their respective financial statements for the years endedDecember 31, 2022, 2021, and 2020: For the Year Ended December 31, (In thousands) 2022 2021 2020 Net sales $720,120 $540,139 $392,231 Gross profit 162,575 80,550 54,838 Net income 132,065 55,059 31,030 The financial position of Sisecam Wyoming is summarized as follows: December 31, (In thousands) 2022 2021 Current assets $340,437 $206,315 Noncurrent assets 292,915 297,210 Current liabilities 111,258 73,181 Noncurrent liabilities 144,290 124,749 60Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 9. Mineral Rights, Net The Partnership’s mineral rights consist of the following: December 31, 2022 2021 (In thousands) Carrying Value AccumulatedDepletion Net BookValue Carrying Value AccumulatedDepletion Net BookValue Coal properties $661,812 $(269,037) $392,775 $670,650 $(253,503) $417,147 Aggregates properties 8,655 (3,410) 5,245 8,747 (2,975) 5,772 Oil and gas royalty properties 12,354 (9,600) 2,754 12,354 (9,115) 3,239 Other 13,150 (1,612) 11,538 13,151 (1,612) 11,539 Total mineral rights, net $695,971 $(283,659) $412,312 $704,902 $(267,205) $437,697 Depletion expense related to the Partnership’s mineral rights is included in depreciation, depletion and amortization on its Consolidated Statements ofComprehensive Income (Loss) and totaled $20.9 million, $17.6 million and $8.8 million for the year ended December 31, 2022, 2021 and 2020, respectively. Impairment of Mineral Rights During the years ended December 31, 2022, 2021 and 2020, the Partnership identified facts and circumstances that indicated that the carrying value of certain of itsmineral rights exceed future cash flows from those assets and recorded non-cash impairment expense included in asset impairments on the Consolidated Statements ofComprehensive Income (Loss) as follows: For the Year Ended December 31, (In thousands) 2022 2021 2020 Coal properties (1) $4,365 $5,015 $114,302 Aggregates properties (2) 92 87 21,583 Total $4,457 $5,102 $135,885 (1)The Partnership recorded $4.4 million of impairment expense during the year ended December 31, 2022, primarily related to assets whose undiscounted future netcash flows were less than their net book values. Of this amount, $2.6 million of impairment expense related to an asset with $4.3 million of net book value, resultingin a fair value of $1.7 million at December 31, 2022. The fair value of the impaired asset at December 31, 2022 was calculated using a discount rate of 15%. ThePartnership recorded $5.0 million of impairment expense during the year ended December 31, 2021 primarily related to the full impairment of an asset resulting from alease termination. The partnership recorded $114.3 million of impairment expense to impair certain assets during the year ended December 31, 2020 primarilyrelated to weakened coal markets that resulted in termination of certain coal leases and changes to lessee mine plans resulting in permanent moves off certain of ourcoal properties. NRP compared the net book value of its coal properties to estimated undiscounted future net cash flows. If the net book value exceeded theundiscounted future cash flows, the Partnership recorded an impairment for the excess of the net book value over fair value. A discounted cash flow model wasused to estimate the level 3 fair value. Significant inputs used to determine fair value include estimates of future cash flows from coal sales and minimum payments,discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date andincluded an adjustment for risk related to the future realization of cash flows.(2)The Partnership recorded $0.1 million of aggregates royalty property impairments during the year ended December 31, 2022 and 2021. The Partnership recorded$21.6 million of aggregates royalty property impairments during the year ended December 31, 2020 primarily related to decreased oil and gas drilling activity whichnegatively impacted the outlook for NRP's frac sand properties. NRP compared the net book value of its aggregates and timber properties to estimatedundiscounted future net cash flows. If the net book value exceeded the undiscounted cash flows, the Partnership recorded an impairment for the excess of the netbook value over fair value. A discounted cash flow model was used to estimate the level 3 fair value. Significant inputs used to determine fair value includeestimates of future cash flows from aggregates sales and minimum payments, discount rate and useful economic life. Estimated cash flows are the product of aprocess that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows. While the Partnership's impairment evaluation as of December 31, 2022 incorporated an estimated impact of the global COVID-19 pandemic, there is significantuncertainty as to the severity and duration of this disruption. If the impact is worse than we currently estimate, an additional impairment charge may be recognized infuture periods. 61Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 10. Intangible Assets, Net The Partnership's intangible assets consist of above-market coal royalty and related transportation contracts with subsidiaries of Foresight Energy ResourcesLLC ("Foresight") pursuant to which the Partnership receives royalty payments for coal sales and throughput fees for the transportation and processing of coal. ThePartnership's intangible assets included on its Consolidated Balance Sheets are as follows: December 31, (In thousands) 2022 2021 Intangible assets at cost $51,353 $51,353 Less: accumulated amortization (36,640) (35,223)Total intangible assets, net $14,713 $16,130 Amortization expense included in depreciation, depletion and amortization on the Partnership's Consolidated Statements of Comprehensive Income (Loss) was$1.4 million, $1.3 million and $0.2 million for the year ended December 31, 2022, 2021 and 2020, respectively. The estimates of amortization expense for the years ended December 31, as indicated below, are based on current mining plans and are subject to revision as thoseplans change in future periods. (In thousands) Estimated AmortizationExpense 2023 $990 2024 1,133 2025 1,052 2026 1,052 2027 1,052 62Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 11. Debt, Net The Partnership's debt consists of the following: December 31, (In thousands) 2022 2021 NRP LP debt: 9.125% senior notes, with semi-annual interest payments in June and December, due June 2025 issued at par ("2025 SeniorNotes") $— $300,000 Opco debt: Revolving credit facility $70,000 $— Senior Notes 5.55% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023 $2,366 $4,730 4.73% with semi-annual interest payments in June and December, with annual principal payments in December, dueDecember 2023 6,004 12,008 5.82% with semi-annual interest payments in March and September, with annual principal payments in March, dueMarch 2024 25,368 38,053 8.92% with semi-annual interest payments in March and September, with annual principal payments in March, dueMarch 2024 8,023 12,035 5.03% with semi-annual interest payments in June and December, with annual principal payments in December, dueDecember 2026 45,683 57,104 5.18% with semi-annual interest payments in June and December, with annual principal payments in December, dueDecember 2026 11,643 14,554 Total Opco Senior Notes $99,087 $138,484 Total debt at face value $169,087 $438,484 Net unamortized debt issuance costs (806) (4,939)Total debt, net $168,281 $433,545 Less: current portion of long-term debt (39,076) (39,102)Total long-term debt, net $129,205 $394,443 NRP LP Debt 2025 Senior Notes In 2022, NRP redeemed all $300 million of its 2025 Senior Notes. Included in loss on extinguishment of debt on the Partnership's Consolidated Statements ofComprehensive Income (Loss) for the year ended December 31, 2022, are $7.2 million of call premium and fees and the write off of $3.1 million of debt issuance costs. Thecash paid for call premiums and fees is included in other items, net under cash used in financing activities on the Consolidated Statements of Cash Flows. The followingdescribes the terms of the 2025 Senior Notes prior to their redemption. The 2025 Senior Notes were issued under an Indenture dated as of April 29, 2019 (the "2025 Indenture"), bore interest at 9.125% per year and would have maturedon June 30, 2025. Interest was payable semi-annually on June 30 and December 30. NRP had the option to redeem the 2025 Senior Notes, in whole or in part, at any timeon or after October 30, 2021, at the redemption prices (expressed as percentages of principal amount) of 104.563% for the 12-month period beginning October 30,2021, 102.281% for the 12-month period beginning October 30, 2022, and thereafter at 100.000%, together, in each case, with any accrued and unpaid interest to the dateof redemption. In the event of a change of control, as defined in the 2025 Indenture, the holders of the 2025 Senior Notes may have required us to purchase their 2025Senior Notes at a purchase price equal to 101% of the principal amount of the 2025 Senior Notes, plus accrued and unpaid interest, if any. The 2025 Senior Notes wereissued at par. The 2025 Senior Notes were the senior unsecured obligations of NRP. The 2025 Senior Notes ranked equal in right of payment to all existing and future seniorunsecured debt of NRP and senior in right of payment to any of NRP's subordinated debt. The 2025 Senior Notes were effectively subordinated in right of payment to allfuture secured debt of NRP to the extent of the value of the collateral securing such indebtedness was structurally subordinated in right of payment to all existing andfuture debt and other liabilities of our subsidiaries, including the Opco Credit Facility and each series of Opco’s existing senior notes. None of NRP's subsidiariesguaranteed the 2025 Senior Notes. As of December 31, 2021, NRP was in compliance with the terms of the Indenture relating to their 2025 Senior Notes. 63Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED Opco Debt All of Opco’s debt is guaranteed by its wholly owned subsidiaries and is secured by certain of the assets of Opco and its wholly owned subsidiaries, other thanBRP LLC and NRP Trona LLC. As of December 31, 2022 and 2021, Opco was in compliance with the terms of the financial covenants contained in its debt agreements. Opco Credit Facility In August 2022, the Partnership entered into the Fifth Amendment (the "Fifth Amendment") to the Opco Credit Facility (the "Opco Credit Facility"). The FifthAmendment extended the term of the Opco Credit Facility until August 2027. Lender commitments under the Opco Credit Facility increased to $130.0 million. Indebtedness under the Opco Credit Facility bears interest, at Opco's option, at:•the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50%; or (iii) SOFR plus 1%, in each case plus an applicable marginranging from 2.50% to 3.50%; or•a rate equal to SOFR plus an applicable margin ranging from 3.50% to 4.50%. During the year ended December 31, 2022 the Partnership had $70.0 million in borrowings outstanding under the Opco Credit Facility and $60.0 million ofborrowing capacity as of December 31, 2022. The weighted average interest rate for the borrowings outstanding under the Opco Credit Facility for the year endedDecember 31, 2022 was 7.17%. During the year ended December 31, 2021, the Partnership did not have any borrowings outstanding under the Opco Credit Facility andhad $100.0 million in available borrowing capacity at December 31, 2021. Opco will incur a commitment fee on the unused portion of the revolving credit facility at a rateof 0.50% per annum. Opco may prepay all amounts outstanding under the Opco Credit Facility at any time without penalty. The Opco Credit Facility contains financial covenants requiring Opco to maintain:•A leverage ratio of consolidated indebtedness to EBITDDA (as defined in the Opco Credit Facility) not to exceed 3.0x; and•an interest coverage ratio of consolidated EBITDDA to consolidated interest expense and consolidated lease expense (in each case as defined in the Opco CreditFacility) of not less than 3.5 to 1.0. The Opco Credit Facility contains certain additional customary negative covenants that, among other items, restrict Opco’s ability to incur additional debt, grantliens on its assets, make investments, sell assets and engage in business combinations. Included in the investment covenant are restrictions upon Opco’s ability toacquire assets where Opco does not maintain certain levels of liquidity. In addition, Opco is required to use 75% of the net cash proceeds of certain non-ordinary courseasset sales to repay the Opco Credit Facility (without any corresponding commitment reduction) and use the remaining 25% of the net cash proceeds to offer to repayits Senior Notes on a pro-rata basis, as described below under “—Opco Senior Notes.” The Opco Credit Facility also contains customary events of default, includingcross-defaults under Opco’s Senior Notes. The Opco Credit Facility is collateralized and secured by liens on certain of Opco’s assets with carrying values of $326.4 million and $345.0 million classified asmineral rights, net and other long-term assets, net on the Partnership’s Consolidated Balance Sheets as of December 31, 2022 and 2021, respectively. The collateralincludes (1) the equity interests in all of Opco’s wholly owned subsidiaries, other than BRP LLC and NRP Trona LLC (which owns a 49% non-controlling equity interestin Sisecam Wyoming), (2) the personal property and fixtures owned by Opco’s wholly owned subsidiaries, other than BRP LLC and NRP Trona LLC, (3) Opco’s materialcoal royalty revenue producing properties, and (4) certain of Opco’s coal-related infrastructure assets. 6464Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED Opco Senior Notes Opco has issued several series of private placement senior notes (the "Opco Senior Notes") with various interest rates and principal due dates. As of December31, 2022 and 2021, the Opco Senior Notes had cumulative principal balances of $99.1 million and $138.5 million, respectively. Opco made mandatory principal paymentson the Opco Senior Notes of $39.4 million, $39.4 million and $46.2 million during the year ended December 31, 2022, 2021 and 2020, respectively. The Note Purchase Agreements relating to the Opco Senior Notes contain covenants requiring Opco to:•maintain a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the note purchase agreement) of no more than 4.0 to 1.0 for the four mostrecent quarters;•not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement);and•maintain the ratio of consolidated EBITDDA (as defined in the note purchase agreement) to consolidated fixed charges (consisting of consolidated interest expenseand consolidated operating lease expense) at not less than 3.5 to 1.0. In addition, the Note Purchase Agreements include a covenant that provides that, in the event NRP Operating or any of its subsidiaries is subject to anyadditional or more restrictive covenants under the agreements governing its material indebtedness (including the Opco Credit Facility and all renewals, amendments orrestatements thereof), such covenants shall be deemed to be incorporated by reference in the Note Purchase Agreements and the holders of the Notes shall receive thebenefit of such additional or more restrictive covenants to the same extent as the lenders under such material indebtedness agreement. The 8.92% Opco Senior Notes also provides that in the event that Opco’s leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined inthe Note Purchase Agreements) exceeds 3.75 to 1.00 at the end of any fiscal quarter, then in addition to all other interest accruing on these notes, additional interest inthe amount of 2.00% per annum shall accrue on the notes for the two succeeding quarters and for as long thereafter as the leverage ratio remains above 3.75 to 1.00.Opco has not exceeded the 3.75 to 1.00 ratio at the end of any fiscal quarter through December 31, 2022. In September 2016, Opco amended the Opco Senior Notes. Under this amendment, Opco agreed to use certain asset sale proceeds to make mandatory prepaymentoffers to the holders of the Opco Senior Notes using an amount of net cash proceeds from certain asset sales that will be calculated pro-rata based on the amount ofOpco Senior Notes then outstanding compared to the other total Opco senior debt outstanding that is being prepaid. The mandatory prepayment offers described above will be made pro-rata across each series of outstanding Opco Senior Notes and will not require any make-wholepayment by Opco. In addition, the remaining principal and interest payments on the Opco Senior Notes will be adjusted accordingly based on the amount of OpcoSenior Notes actually prepaid. The prepayments do not affect the maturity dates of any series of the Opco Senior Notes. Consolidated Principal Payments The consolidated principal payments due are set forth below: NRP LP Opco (In thousands) Senior Notes Senior Notes Credit Facility Total 2023 $— $39,396 $— $39,396 2024 — 31,028 — 31,028 2025 — 14,332 — 14,332 2026 — 14,331 — 14,331 2027 — — 70,000 70,000 Thereafter — — — — $— $99,087 $70,000 $169,087 65Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 12. Fair Value Measurements Fair Value of Financial Assets and Liabilities The Partnership’s financial assets and liabilities consist of cash and cash equivalents, a contract receivable and debt. The carrying amounts reported on theConsolidated Balance Sheets for cash and cash equivalents approximate fair value due to their short-term nature. The Partnership uses available market data andvaluation methodologies to estimate the fair value of its debt and contract receivable. The following table shows the carrying value and estimated fair value of the Partnership's debt and contract receivable: December 31, 2022 2021 Carrying Estimated Carrying Estimated (In thousands) Fair Value Hierarchy Level Value Fair Value Value Fair Value Debt: NRP 2025 Senior Notes 1 $— $— $296,236 $300,000 Opco Senior Notes (1) (2) 3 98,281 96,060 137,309 138,484 Opco Credit Facility (3) 3 70,000 70,000 — — Assets: Contract receivable, net (current and long-term) (4) 3 $31,371 $24,833 $33,612 $26,010 (1)The fair value of the Opco Senior Notes at December 31, 2022 was estimated by management utilizing the present value replacement method incorporating theinterest rate of the Opco Credit Facility at December 31, 2022.(2)The fair value of the Opco Senior Notes at December 31, 2021 was estimated by management using quotations obtained for the NRP 2025 Senior Notes on theclosing trading prices near period end, which were at 100% of par value.(3)The fair value of the Opco Credit Facility approximates the outstanding borrowing amount because the interest rates are variable and reflective of market rates andthe terms of the credit facility allow the Partnership to repay this debt at any time without penalty.(4)The fair value of the Partnership's contract receivable was determined based on the present value of future cash flow projections related to the underlying asset at adiscount rate of 15% at December 31, 2022 and 2021. NRP has embedded derivatives in the preferred units related to certain conversion options, redemption features and the change of control provision that areaccounted for separately from the preferred units as assets and liabilities at fair value on the Partnership's Consolidated Balance Sheets. Level 3 valuation of theembedded derivatives are based on numerous factors including the likelihood of the event occurring. The embedded derivatives are revalued quarterly and changes intheir fair value would be recorded in other expenses, net on the Partnership's Consolidated Statements of Comprehensive Income (Loss). The embedded derivatives hadzero value as of December 31, 2022 and 2021. Fair Value of Non-Financial Assets The Partnership discloses or recognizes its non-financial assets, such as impairments of coal and aggregates properties at fair value on a nonrecurring basis. Referto Note 9. Mineral Rights, Net for additional disclosures related to the fair value associated with the impaired assets. 66Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 13. Related Party Transactions Affiliates of our General Partner The Partnership’s general partner does not receive any management fee or other compensation for its management of NRP. However, in accordance with thepartnership agreement, the general partner and its affiliates are reimbursed for services provided to the Partnership and for expenses incurred on the Partnership’sbehalf. Employees of Quintana Minerals Corporation ("QMC") and Western Pocahontas Properties Limited Partnership ("WPPLP"), affiliates of the Partnership, providetheir services to manage the Partnership's business. QMC and WPPLP charge the Partnership the portion of their employee salary and benefits costs related to theiremployee services provided to NRP. These QMC and WPPLP employee management service costs are presented as operating and maintenance expenses and generaland administrative expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss). NRP also reimburses overhead costs incurred by itsaffiliates, including Quintana Infrastructure Development ("QID"), to manage the Partnership's business. These overhead costs include certain rent, informationtechnology, administration of employee benefits and other corporate services incurred by or on behalf of the Partnership’s general partner and its affiliates and arepresented as operating and maintenance expenses and general and administrative expenses on the Partnership's Consolidated Statements of Comprehensive Income(Loss). Direct general and administrative expenses charged to the Partnership by QMC, WPPLP and QID are included on the Partnership's Consolidated Statement ofComprehensive Income (Loss) as follows: For the Year Ended December 31, (In thousands) 2022 2021 2020 Operating and maintenance expenses $6,694 $6,543 $6,559 General and administrative expenses 4,864 4,611 4,611 The Partnership had accounts payable to QMC of $0.4 million on its Consolidated Balance Sheets at both December 31, 2022 and 2021 and $1.0 million and$0.9 million of accounts payable to WPPLP at December 31, 2022 and 2021, respectively. During the years ended December 31, 2022, 2021 and 2020, the Partnership recognized $8.5 million, $3.3 million and $0.4 million in operating and maintenanceexpenses, respectively, on its Consolidated Statements of Comprehensive Income (Loss) related to an overriding royalty agreement with WPPLP. Corbin J. Robertson, Jr. owns 85% of the general partner of Great Northern Properties Limited Partnership ("GNP"), a privately held company primarily engaged inowning and managing mineral properties and surface leases. As of December 31, 2022 and 2021 Partnership had $0.03 million and $0.1 million, respectively of accountsreceivable from GNP included in accounts receivable, net on its Consolidated Balance Sheets related to amounts collected for surface leases that belong to NRP. 67Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 14. Major Customers Revenues from customers that exceeded 10 percent of total revenues for any of the periods presented below are as follows: For the Year Ended December 31, 2022 2021 2020 (In thousands) Revenues Percent Revenues Percent Revenues Percent Alpha Metallurgical Resources, Inc. (1) $102,352 26% $49,440 23% $33,227 24%Foresight (1) (2) 65,597 17% 37,366 17% 35,704 26% (1)Revenues from Alpha Metallurgical Resources, Inc. and Foresight are included within the Partnership's Mineral Rights segment.(2)Revenues from Foresight in 2020 and 2021 were fixed as a result of the lease amendment the Partnership entered into with Foresight pursuant to which Foresightagreed to pay NRP fixed cash payments to satisfy all obligations arising out of the existing various coal mining leases and transportation infrastructure feeagreements between the Partnership and Foresight. Revenues from Foresight in 2022 represent traditional royalty and minimum payments. 15. Commitments and Contingencies Legal NRP is involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannotbe predicted with certainty, Partnership management believes these ordinary course matters will not have a material effect on the Partnership’s financial position,liquidity or operations. Environmental Compliance The operations the Partnership’s lessees conduct on its properties, as well as the industrial minerals, aggregates and oil and gas operations in which thePartnership has interests, are subject to federal and state environmental laws and regulations. See "Items 1. and 2. Business and Properties—Regulation andEnvironmental Matters." As an owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring on thesurface properties. The terms of substantially all of the Partnership’s coal leases require the lessee to comply with all applicable laws and regulations, includingenvironmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially allof the leases require the lessee to indemnify the Partnership against, among other things, environmental liabilities. Some of these indemnifications survive thetermination of the lease. The Partnership makes regular visits to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests withthe lessees. The Partnership believes that its lessees will be able to comply with existing regulations and does not expect that any lessee’s failure to comply withenvironmental laws and regulations will have a material impact on the Partnership’s financial condition or results of operations. The Partnership has neither incurred, noris aware of, any material environmental charges imposed on the Partnership related to its properties for the period ended December 31, 2022. The Partnership is notassociated with any material environmental contamination that may require remediation costs. However, the Partnership’s lessees are required to conduct reclamationwork on the properties under lease to them. Because the Partnership is not the permittee of the mines being reclaimed, the Partnership is not responsible for the costsassociated with these reclamation operations. As a former owner of the working interests in oil and natural gas operations, the Partnership is responsible for its proportionate share of any losses and liabilities,including environmental liabilities, arising from uninsured and underinsured events during the period it was an owner. 68Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 16. Unit-Based Compensation 2017 Long-Term Incentive Plan In December 2017, the 2017 Long-Term Incentive Plan (the “2017 LTIP”) was approved and it became effective in January 2018. The 2017 LTIP authorizes a total of1,600,000 common units that are available for delivery by the Partnership pursuant to awards under the plan. The initial number of common units authorized for issuancepursuant to awards under the plan was 800,000 and in March 2022, an additional 800,000 units were authorized for issuance. The term is 10 years from the date ofapproval of the Board of Directors or, if earlier, the date the 2017 LTIP is terminated by the Board of Directors or the committee appointed by the Board of Directors toadminister the 2017 LTIP, or the date all available common units available have been delivered. Common units delivered pursuant to the 2017 LTIP will consist, in wholeor part, of (i) common units acquired in the open market, (ii) common units acquired from the Partnership (including newly issued units), any of our affiliates or any otherperson or (iii) any combination of the foregoing. Employees, consultants and non-employee directors of the Partnership, the General Partner, GP LLC and their affiliates are generally eligible to receive awardsunder the 2017 LTIP. The 2017 LTIP provides for the issuance of a variety of equity-based grants, including grants of (i) options, (ii) unit appreciation rights, (iii)restricted units, (iv) phantom units, (v) cash awards, (vi) performance awards, (vii) distribution equivalent rights, and (viii) other unit-based awards. The plan isadministered by the Compensation, Nominating and Governance Committee ("CNG Committee") of the Board of Directors, which determines the terms and conditions ofawards granted under the 2017 LTIP. The Partnership recognizes forfeitures for any awards issued under this plan as they occur. Unit-Based Awards Unit-based awards under the 2017 LTIP are generally issued to certain employees and non-employee directors of the Partnership. Awards granted to employeeseither vest 3 years following the grant date or vest ratably over the 3 year period following the grant date. Awards granted to non-employee directors vest over a 1 yearperiod. Directors are given the option to take immediate issuance of the vested awards or defer such issuance until a later date. Upon deferral of issuance, such units willcontinue to accumulate distribution equivalent rights ("DERs") until issuance. In connection with the phantom unit awards, the CNG Committee also granted tandem DERs, which entitle the holders to receive distributions equal to thedistributions paid on the Partnership’s common units between the date the units are granted and the settlement date. The DERs are payable in cash upon vesting butmay be subject to forfeiture if the grantee ceases employment prior to vesting. The Partnership's unit-based awards granted in 2022, 2021 and 2020 were valued using the closing price of NRP's units as of the grant date. The grant date fairvalue of these awards granted during the year ended December 31, 2022, 2021 and 2020 were $7.9 million, $3.8 million and $3.5 million, respectively. Total unit-basedcompensation expense associated with these awards was $5.8 million, $4.0 million and $3.6 million for the year ended December 31, 2022, 2021 and 2020, respectively, andis included in general and administrative expenses and operating and maintenance expenses on the Partnership's Consolidated Statements of Comprehensive Income(Loss). The unamortized cost associated with unvested outstanding awards as of December 31, 2022 is $6.3 million, which is to be recognized over a weighted averageperiod of 1.9 years. The unamortized cost associated with unvested outstanding awards as of December 31, 2021 was $3.3 million. A summary of the unit activity in the outstanding grants during 2022 is as follows: (In thousands) Common Units Weighted Average Grant DateFair value per Common Unit Outstanding grants at January 1, 2022 411 $23.00 Granted 208 $38.29 Fully vested and issued (233) $26.74 Outstanding at December 31, 2022 386 $28.96 69Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 17. Financing Transaction The Partnership owns rail loadout and associated infrastructure at the Sugar Camp mine in the Illinois Basin operated by a subsidiary of Foresight. Theinfrastructure at the Sugar Camp mine is leased to a subsidiary of Foresight and is accounted for as a financing transaction (the "Sugar Camp lease"). The Sugar Camplease expires in 2032 with renewal options for up to 80 additional years. Minimum payments are $5.0 million per year through the end of the lease term. The $5.0 milliondue to the Partnership in 2020 and 2021 was included in the fixed cash payments from Foresight resulting from contract modifications entered into during the secondquarter of 2020 as discussed in Note 14. Major Customers. The Partnership is also entitled to variable payments in the form of throughput fees determined based on theamount of coal transported and processed utilizing the Partnership's assets. In the event the Sugar Camp lease is renewed beyond 2032, payments become a fixed $10thousand per year for the remainder of the renewed term. 18. Credit Losses The Partnership is exposed to credit losses through collection of its trade receivables resulting from contracts with customers and a long-term receivable resultingfrom a financing transaction with a customer. The Partnership records an allowance for current expected credit losses on these receivables based on the loss-ratemethod. NRP assessed the likelihood of collection of its receivables utilizing historical loss rates, current market conditions that included the estimated impact of theglobal COVID-19 pandemic, industry and macroeconomic factors, reasonable and supportable forecasts and facts or circumstances of individual customers andproperties. Examples of these facts or circumstances include, but are not limited to, contract disputes or renegotiations with the customer and evaluation of short andlong-term economic viability of the contracted property. For its long-term contract receivable, management reverts to the historical loss experience immediately after thereasonable and supportable forecast period ends. As of December 31, 2022 and 2021, NRP recorded the following current expected credit loss (“CECL”) related to its receivables and long-term contract receivable: December 31, 2022 2021 (In thousands) Gross CECLAllowance Net Gross CECLAllowance Net Receivables $47,237 $(4,461) $42,776 $28,869 $(3,312) $25,557 Long-term contract receivable 29,984 (1,038) 28,946 32,497 (1,126) 31,371 Total $77,221 $(5,499) $71,722 $61,366 $(4,438) $56,928 NRP recorded $1.1 million, $0.5 million and $0.0 million in operating and maintenance expenses on its Consolidated Statements of Comprehensive Income (Loss)related to the change in the CECL allowance during the year ended December 31, 2022, 2021 and 2020, respectively. NRP has procedures in place to monitor its ongoing credit exposure through timely review of counterparty balances against contract terms and due dates, accountand financing receivable reconciliations, bankruptcy monitoring, lessee audits and dispute resolution. The Partnership may employ legal counsel or collectionspecialists to pursue recovery of defaulted receivables. 70Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 19. Leases As of December 31, 2022, the Partnership had one operating lease for an office building that is owned by WPPLP. On January 1, 2019, the Partnership entered intoa new lease of the building with a five-year base term and five additional five-year renewal options. Upon lease commencement and as of December 31, 2022 and 2021,the Partnership was reasonably certain to exercise all renewal options included in the lease and capitalized the right-of-use asset and corresponding lease liability on itsConsolidated Balance Sheets using the present value of the future lease payments over 30 years. The Partnership's right-of-use asset and lease liability included withinother long-term assets, net and other non-current liabilities, respectively, on its Consolidated Balance Sheets totaled $3.5 million at both December 31, 2022 and 2021.During the years ended December 31, 2022, 2021 and 2020, the Partnership incurred total operating lease expenses of $0.5 million, included in both operating andmaintenance expenses and general and administrative expenses on its Consolidated Statements of Comprehensive Income (Loss). The following table details the maturity analysis of the Partnership's operating lease liability and reconciles the undiscounted cash flows to the operating leaseliability included on its Consolidated Balance Sheet: Remaining Annual Lease Payments (In thousands) December 31, 2022 2023 $483 2024 483 2025 483 2026 483 2027 483 After 2027 10,147 Total lease payments (1) $12,562 Less: present value adjustment (2) (9,092)Total operating lease liability $3,470 (1)The remaining lease term of the Partnership's operating lease is 26 years.(2)The present value of the operating lease liability on the Partnership's Consolidated Balance Sheets was calculated using a 13.5% discount rate which represents thePartnership's estimated incremental borrowing rate under the lease. As the Partnership's lease does not provide an implicit rate, the Partnership estimated theincremental borrowing rate at the time the lease was entered into by utilizing the rate of the Partnership's secured debt and adjusting it for factors that reflect theprofile of borrowing over the 30-year expected lease term. 71Table of Contents ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures We carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of theExchange Act) as of December 31, 2022. This evaluation was performed under the supervision and with the participation of our management, including the ChiefExecutive Officer and Chief Financial Officer of GP Natural Resource Partners LLC, our managing general partner. Based upon that evaluation, the Chief Executive Officerand Chief Financial Officer concluded that these disclosure controls and procedures were effective as of December 31, 2022 at the reasonable assurance level inproducing the timely recording, processing, summary and reporting of information and in accumulation and communication of information to management to allow fortimely decisions with regard to required disclosures. Management’s Report on Internal Control Over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of GPNatural Resource Partners LLC, our managing general partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting as ofDecember 31, 2022 based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission"2013 Framework" (COSO). Based on that evaluation, as of December 31, 2022, our management concluded that our internal control over financial reporting was effectiveat a reasonable assurance level based on those criteria. No changes were made to our internal control over financial reporting during the last fiscal quarter that materiallyaffected, or are reasonably likely to materially affect, our internal control over financial reporting. Ernst & Young, LLP, the independent registered public accounting firm who audited the Partnership’s consolidated financial statements included in this AnnualReport on Form 10-K, has issued a report on the Partnership’s internal control over financial reporting, which is included herein. 72Table of Contents Report of Independent Registered Public Accounting Firm The Partners of Natural Resource Partners L.P. Opinion on Internal Control Over Financial Reporting We have audited Natural Resource Partners L.P.’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, NaturalResource Partners L.P. (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on theCOSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheetsof Natural Resource Partners L.P. as of December 31, 2022 and 2021, the related consolidated statements of comprehensive income (loss), partners’ capital and cash flowsfor each of the three years in the period ended December 31, 2022, and the related notes and our report dated March 2, 2023 expressed an unqualified opinion thereon. Basis for Opinion The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internalcontrol over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express anopinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required tobe independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities andExchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assuranceabout whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating thedesign and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in thecircumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control Over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and thepreparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financialreporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactionsand dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financialstatements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance withauthorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition,use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectivenessto future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies orprocedures may deteriorate. /s/ Ernst & Young LLP Houston, TexasMarch 2, 2023 73Table of Contents ITEM 9B. OTHER INFORMATION None. 74Table of Contents PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE MANAGING GENERAL PARTNER AND CORPORATE GOVERNANCE As a master limited partnership, we do not employ any of the people responsible for the management of our properties. Instead, we reimburse affiliates of ourmanaging general partner, GP Natural Resource Partners LLC, for their services. The following table sets forth information concerning the directors and officers of GPNatural Resource Partners LLC as of the date of this Annual Report on Form 10-K. Each officer and director is elected for their respective office or directorship on anannual basis. Subject to Board Representation and Observation Rights Agreement with Blackstone and GoldenTree, Mr. Robertson is entitled to appoint the members ofthe Board of Directors of GP Natural Resource Partners LLC. Mr. Robertson has delegated the right to appoint one director to Blackstone. Name Age Position with the General PartnerCorbin J. Robertson, Jr. 75 Chairman of the Board and Chief Executive OfficerCraig W. Nunez 61 President and Chief Operating OfficerChristopher J. Zolas 48 Chief Financial Officer and TreasurerKevin J. Craig 54 Executive Vice PresidentPhilip T. Warman 52 General Counsel and SecretaryGregory F. Wooten 67 Senior Vice President, Chief EngineerGaldino J. Claro 63 DirectorAlexander D. Greene 64 DirectorS. Reed Morian 77 DirectorPaul B. Murphy, Jr. 63 DirectorRichard A. Navarre 62 DirectorCorbin J. Robertson, III 52 DirectorStephen P. Smith 62 DirectorLeo A. Vecellio, Jr. 76 Director Corbin J. Robertson, Jr. has served as Chief Executive Officer and Chairman of the Board of Directors of GP Natural Resource Partners LLC since 2002. Mr.Robertson has vast business experience having founded and served as a director and as an officer of multiple companies, both private and public, and has served onthe boards of numerous non-profit organizations. He has served as the Chief Executive Officer and Chairman of the Board of the general partner of Great NorthernProperties Limited Partnership since 1992 and Quintana Minerals Corporation since 1978, as Chairman of the Board of Directors of New Gauley Coal Corporation since1986, and the general partner of Western Pocahontas Properties Limited Partnership since 1986. Mr. Robertson is also Chief Executive Officer and a member of the Boardof Managers of Pocahontas Royalties LLC. He also serves as a Principal with Quintana Capital Group, Chairman of the Board of the Cullen Trust for Higher Educationand on the boards of the American Petroleum Institute, the National Petroleum Council, the Baylor College of Medicine and the Spirit Golf Association. In 2006, Mr.Robertson was inducted into the Texas Business Hall of Fame. Mr. Robertson is the father of Corbin J. Robertson, III. Craig W. Nunez has served as President and Chief Operating Officer of GP Natural Resource Partners LLC since August 2017 and previously served as ChiefFinancial Officer and Treasurer of GP Natural Resource Partners LLC from January 2015 to August 2017. Prior to joining NRP, Mr. Nunez was an owner and ChiefExecutive Officer of Bocage Group, a private investment company specializing in energy, natural resources and master limited partnerships since March 2012. Inaddition, until joining NRP, he was a FINRA-registered Investment Advisor Representative with Searle & Co since July 2012 and served as an Executive Advisor toCapital One Asset Management since January 2014. From September 2011 through March 2012, Mr. Nunez served as the Executive Vice President and Chief FinancialOfficer of Quicksilver Resources Canada, Inc. Mr. Nunez was Senior Vice President and Treasurer of Halliburton Company from January 2007 until September 2011, andVice President and Treasurer of Halliburton Company from February 2006 to January 2007. Prior to that, he was Treasurer of Colonial Pipeline Company from November1995 to February 2006. Mr. Nunez has been involved in numerous charitable organizations and currently serves on the boards of Goodwill Industries of Houston andMedical Bridges, Inc. Christopher J. Zolas has served as Chief Financial Officer and Treasurer of GP Natural Resource Partners LLC since August 2017 and previously served as ChiefAccounting Officer of GP Natural Resource Partners from March 2015 to August 2017. Prior to joining NRP, Mr. Zolas served as Director of Financial Reporting atCheniere Energy, Inc., a publicly traded energy company, where he performed financial statement preparation and analysis, technical accounting and SEC reporting forfive separate SEC registrants, including a master limited partnership. Mr. Zolas joined Cheniere Energy, Inc. in 2007 as Manager of SEC Reporting and TechnicalAccounting and was promoted to Director in 2009. Prior to joining Cheniere Energy, Inc., Mr. Zolas worked in public accounting with KPMG LLP from 2002 to 2007. Kevin J. Craig was named Executive Vice President of GP Natural Resource Partners LLC in February 2021, after serving as Executive Vice President, Coal of GPNatural Resource Partners since September 2014. Mr. Craig was the Vice President of Business Development for GP Natural Resource Partners LLC since 2005. Mr. Craigalso represents NRP as one of its appointees to the Board of Managers of Sisecam Wyoming LLC. Mr. Craig joined NRP in 2005 from CSX Transportation. He hasextensive marketing, finance and operations experience within the energy industry. Mr. Craig served as a member of the West Virginia House of Delegates having beenelected in 2000 and re-elected in 2002, 2004, 2006, 2008, 2010 and 2012. In addition to other leadership positions, Delegate Craig served as Chairman of the Committee onEnergy. Mr. Craig did not seek re-election in 2014 and his term ended January 2015. Prior to joining CSX, he served as a Captain in the United States Army. Mr. Craig hasserved as the Chairman of the Huntington Regional Chamber of Commerce Board of Directors and continues as a member of both the West Virginia Chamber ofCommerce and the Huntington Regional Chamber of Commerce’s respective board of directors. He serves as a member of the Board of Directors of Encova MutualInsurance Company, the West Virginia University Board of Governors and the WVU Medicine Board of Governors. 75Table of Contents Philip T. Warman has served as General Counsel and Secretary of GP Natural Resource Partners LLC since August 2021. Mr. Warman previously served asExecutive Vice President, General Counsel and Secretary of SandRidge Energy Inc. from August 2010 until June 2019. He was Associate General Counsel for SEC andfinance matters for Spectra Energy Corporation from January 2007 through July 2010. From 1998 through 2006 he practiced law as a corporate finance attorney withVinson & Elkins, LLP in Houston, Texas. Mr. Warman earned a Bachelor of Science in Chemical Engineering from the University of Houston in 1993 and graduated fromthe University of Texas School of Law in 1998. Gregory F. Wooten was named Senior Vice President, Chief Engineer of GP Natural Resource Partners LLC in February 2021, after serving as Vice President, ChiefEngineer of GP Natural Resource Partners LLC since December 2013. Mr. Wooten joined NRP in 2007, serving as Regional Manager. Prior to joining NRP, Mr. Wootenserved as Vice President, Chief Operating Officer and Chief Engineer of Dingess Rum Properties, Inc., where he managed coal, oil, gas and timber properties from 1982until 2007. Mr. Wooten has over 35 years of experience in the coal industry, working as a planning and production engineer and is a member of the American Institute ofMining, Metallurgical, and Petroleum Engineers. Mr. Wooten also serves as the President of the National Council of Coal Lessors and is a board member of the WestVirginia, Kentucky, Indiana and Montana Coal Council. He also serves on the board of the Cabell-Huntington Hospital and is a member of the West Virginia SchoolBuilding Authority. Galdino J. Claro joined the Board of Directors of GP Natural Resource Partners LLC in March 2018. Mr. Claro has 30 years of worldwide executive leadershipexperience in the primary and secondary metals industries. From October 2013 to August 2017, Mr. Claro served as the Group Chief Executive Officer and ManagingDirector of Sims Metal Management where he was also a member of the Safety, Health, Environment and Sustainability Committee, the Nomination GovernanceCommittee and the Finance Investment Committee. Before joining Sims Metal Management, Mr. Claro served for four years as the Chief Executive Officer of HarscoMetals and Minerals. He joined Harsco from Aleris, where he served as CEO of Aleris Americas. Before that, he was the CEO of the Metals Processing Group of HeicoCompanies LLC. During his career with Alcoa Inc., Mr. Claro served for five years as the President of Alcoa China and for six years in Europe as the Vice President ofSoft Alloys Extrusions and the President of Alcoa Europe Extrusions. While in South America, Mr. Claro worked for several different divisions of Alcoa Alumni SA asplant manager, technology manager, new products development director and Managing Director of Alcoa Cargo-Van. Before joining Alcoa in 1985, Mr. Claro started hiscareer at Honda-Motogear as a Quality Control Manager where he worked for three years in both Brazil and Japan. Alexander D. Greene joined the Board of Directors of GP Natural Resource Partners LLC in March 2019. Mr. Greene brings extensive corporate finance and privateequity experience to his role on the Board, with 40 years working with and investing in businesses where operational improvement and strategic guidance were primarydrivers of value creation and as a financial advisor to large and mid-cap companies, boards of directors and other constituencies in complex leveraged finance, mergerand acquisition and recapitalization transactions. Mr. Greene is Chairman of the Board of New RL Holdings LLC and was Chairman of the Board of USA Truck, Inc. priorto its sale in September 2022. From 2005 to 2014 he was a Managing Partner and head of U.S. Private Equity at Brookfield Asset Management, a global assetmanagement company. Prior to Brookfield, Mr. Greene was a Managing Director and co-head of Carlyle Strategic Partners, a private equity fund, and a ManagingDirector and investment banker at Wasserstein Perella & Co. and Whitman Heffernan Rhein & Co. Mr. Greene is a volunteer firefighter and president of the ArmonkIndependent Fire Company. Mr. Greene has been designated to serve as a director of GP Natural Resource Partners LLC by Blackstone Tactical Opportunities, pursuantto its right to designate a director to the Board of Directors of GP Natural Resource Partners LLC. S. Reed Morian joined the Board of Directors of GP Natural Resource Partners LLC in 2002. Mr. Morian has vast executive business experience having served asChairman and Chief Executive Officer of several companies since the early 1980s and serving on the board of other companies. Mr. Morian has served as a member ofthe Board of Directors of the general partner of Western Pocahontas Properties Limited Partnership since 1986, New Gauley Coal Corporation since 1992 and the generalpartner of Great Northern Properties Limited Partnership since 1992. Mr. Morian also serves on the Board of Managers of Pocahontas Royalties, LLC. Mr. Morianworked for Dixie Chemical Company from 1971 to 2006 and served as its Chairman and Chief Executive Officer from 1981 to 2006. He has also served as Chairman, ChiefExecutive Officer and President of DX Holding Company since 1989. He formerly served on the Board of Directors for the Federal Reserve Bank of Dallas-HoustonBranch from April 2003 until December 2008 and as a Director of Prosperity Bancshares, Inc. from March 2005 until April 2009. He is currently serving on the Board ofDirectors of Gulf Capital Bank in Houston. 76Table of Contents Paul B. Murphy, Jr. joined the Board of Directors of GP Natural Resource Partners LLC in March 2018. Mr. Murphy is the Executive Vice Chairman and a Director ofCadence Bank. Mr. Murphy helped raise $1 billion to invest in the distressed banking industry in 2010. He acquired Cadence Bank and three others and had strong coregrowth reaching $18 billion in assets. In 2021 Cadence merged with BancorpSouth and today the company is $48 billion in assets with 400 branches in 9 states andtrades on the NYSE (CADE). Previously, Mr. Murphy spent 20 years at Amegy Bank of Texas, helping to steer that institution from $75 million in assets and a singlelocation to assets of $11 billion and 85 banking centers at the time of his departure as the Chief Executive Officer and a Director in 2009. Mr. Murphy is an advocate ofthe community and is a board member of Oceaneering International, Inc., Hope and Healing Center and Institute and the Houston Hispanic Chamber of Commerce. Richard A. Navarre joined the Board of Directors of GP Natural Resource Partners LLC in October 2013. Mr. Navarre brings extensive operating, financial, strategicplanning, public company and coal industry experience to the Board of Directors. Mr. Navarre is former Chairman, President and CEO of Covia Holdings, a leadingprovider of high quality minerals and material solutions for the industrial and energy markets. From 1993 until 2012, Mr. Navarre held senior executive positions withPeabody Energy Corporation, including President-Americas, President and Chief Commercial Officer, Executive Vice President of Corporate Development and ChiefFinancial Officer. Mr. Navarre serves on the Board of Directors of Civeo Corporation, where he serves as Chairman and member of the Environmental, Social, Governanceand Nominating Committee and Arch Resources, where he serves as Chairman of the Personnel and Compensation Committee and member of the Environmental, Social,Governance and Nominating and Governance Committee. He is a member of the Hall of Fame of the College of Business and a member of the Board of Advisors of theCollege of Business and Analytics of Southern Illinois University Carbondale. He is the former Chairman of the Bituminous Coal Operators’ Association. Mr. Navarre isa Certified Public Accountant. Mr. Navarre also has been involved in numerous civic and charitable organizations throughout his career. Corbin J. Robertson, III joined the Board of Directors of GP Natural Resource Partners LLC in May 2013. Mr. Robertson has experience with investments in avariety of energy businesses, having served both in management of private equity firms and having served on several boards of directors. He has served as the ChiefExecutive Officer of the general partner of Western Pocahontas Properties Limited Partnership since May 2008, and has served on the Board of Directors of QuintanaMinerals Corporation since 2007 and Western Pocahontas since October 2012. Mr. Robertson also has served on the Board of Managers of Premium Resources, LLCsince 2016. Mr. Robertson also co-founded Quintana Energy Partners, an energy-focused private equity firm in 2006, and served as a Managing Director thereof from2006 until December 2010. Mr. Robertson has served on the Board of Directors for Quintana Minerals Corporation since October 2007, and previously served as VicePresident-Acquisitions for GP Natural Resource Partners LLC from 2003 until 2005. Mr. Robertson also serves on the Board of Directors of Quality Magnetite, QuinwoodCoal and LL&B Minerals, each of which is in the energy business. Mr. Robertson is the son of Corbin J. Robertson, Jr. Mr. Robertson previously served as Co-Managing Partner of LKCM Headwater Investments GP, LLC, LKCM Headwater Investments I, L.P., LKCM Headwater Investments II, LP, LKCM Headwater InvestmentsII Sidecar, LP, LKCM Headwater Investments III, private equity funds that began June 2011. Stephen P. Smith joined the Board of Directors of GP Natural Resource Partners LLC in 2004. Mr. Smith brings extensive public company financial experience in thepower and energy industries to the Board of Directors. Mr. Smith formerly served as Chief Financial Officer, Chief Accounting Officer and Director of the general partnerof Columbia Pipeline Partners L.P. from September 2014 until June 2016. Mr. Smith also formerly served as Executive Vice President and Chief Financial Officer ofColumbia Pipeline Group from July 2015 to June 2016. Mr. Smith served as Executive Vice President and Chief Financial Officer for NiSource, Inc. from August 2008 toJune 2015. Prior to joining NiSource, he held several positions with American Electric Power Company, Inc, including Senior Vice President - Shared Services fromJanuary 2008 to June 2008, Senior Vice President and Treasurer from January 2004 to December 2007, and Senior Vice President - Finance from April 2003 to December2003. Leo A. Vecellio, Jr. joined the Board of Directors of GP Natural Resource Partners LLC in May 2007. Mr. Vecellio brings extensive experience in the aggregates andcoal mine development industry to the Board of Directors. Mr. Vecellio and his family have been in the aggregates materials and construction business since the late1930s. Since November 2002, Mr. Vecellio has served as Chairman and Chief Executive Officer of Vecellio Group, Inc, a major aggregates producer, contractor and oilterminal developer/operator in the Mid-Atlantic and Southeastern states. For nearly 30 years prior to that time Mr. Vecellio served in various capacities with Vecellio &Grogan, Inc., having most recently served as Chairman and Chief Executive Officer from April 1996 to November 2002. Mr. Vecellio is the former Chairman of theAmerican Road and Transportation Builders and is a longtime member of the Florida Council of 100, as well as many other civic and charitable organizations. 77Table of Contents Corporate Governance Board Meetings and Executive Sessions The Board met seven times in 2022. During 2022, our non-management directors met in executive session several times. The presiding director was Mr. Vecellio, theChairman of our Compensation, Nominating and Governance Committee, or CNG Committee. In addition, our independent directors met several times in executivesession in 2022. Mr. Vecellio was the presiding director at those meetings. Interested parties may communicate with our non-management directors by writing a letter tothe Chairman of the CNG Committee, NRP Board of Directors, 1415 Louisiana Street, Suite 3325, Houston, Texas 77002. Independence of Directors The Board of Directors has affirmatively determined that Messrs. Claro, Navarre, Smith, and Vecellio are independent based on all facts and circumstancesconsidered by the Board, including the standards set forth in Section 303A.02(a) of the NYSE’s listing standards. Because we are a limited partnership as defined inSection 303A of the NYSE’s listing standards, we are not required to have a majority of independent directors on the Board. The Board has an Audit Committee, aCompensation, Nominating and Governance Committee, and a Conflicts Committee, each of which is staffed solely by independent directors. Audit Committee Our Audit Committee is comprised of Mr. Smith, who serves as chairman, Mr. Claro and Mr. Navarre. Mr. Smith and Mr. Navarre are "Audit Committee FinancialExperts" as determined pursuant to Item 407 of Regulation S-K. During 2022, the Audit Committee met seven times. Report of the Audit Committee Our Audit Committee is composed entirely of independent directors. The members of the Audit Committee meet the independence and experience requirements ofthe New York Stock Exchange. The Audit Committee has adopted, and annually reviews, a charter outlining the practices it follows. The charter complies with all currentregulatory requirements. The Audit Committee Charter is available on our website at www.nrplp.com and is available in print upon request. During 2022, at each of its meetings, the Audit Committee met with the senior members of our financial management team, our general counsel and ourindependent auditors. The Audit Committee had private sessions at certain of its meetings with our independent auditors and the senior members of our financialmanagement team and the general counsel at which candid discussions of financial management, accounting and internal control and legal issues took place. The Audit Committee approved the engagement of Ernst & Young LLP as our independent auditors for the year ended December 31, 2022 and reviewed with ourfinancial managers and the independent auditors overall audit scopes and plans, the results of internal and external audit examinations, evaluations by the auditors ofour internal controls and the quality of our financial reporting. Management has reviewed the audited financial statements in the Annual Report with the Audit Committee, including a discussion of the quality, not just theacceptability, of the accounting principles, the reasonableness of significant accounting judgments and estimates, and the clarity of disclosures in the financialstatements. In addressing the quality of management’s accounting judgments, members of the Audit Committee asked for management’s representations and reviewedcertifications prepared by the Chief Executive Officer and Chief Financial Officer that our unaudited quarterly and audited consolidated financial statements fairlypresent, in all material respects, our financial condition and results of operations, and have expressed to both management and auditors their general preference forconservative policies when a range of accounting options is available. The Audit Committee has discussed with the independent auditors the matters required to be discussed by the applicable requirements of the Public CompanyAccounting Oversight Board (“PCAOB”) and the Commission. The Audit Committee has received the written disclosures and the letter from the independentaccountant required by applicable requirements of the PCAOB regarding the independent accountant’s communications with the Audit Committee concerningindependence, and has discussed with the independent accountant the independent accountant’s independence. In performing all of these functions, the Audit Committee acts only in an oversight capacity. The Audit Committee reviews our Quarterly Reports on Form 10-Qand Annual Reports on Form 10-K prior to filing with the Securities and Exchange Commission. In 2022, the Audit Committee also reviewed quarterly earningsannouncements with management and representatives of the independent auditor in advance of their issuance. In its oversight role, the Audit Committee relies on thework and assurances of our management, which has the primary responsibility for financial statements and reports, and of the independent auditors, who, in their report,express an opinion on the conformity of our annual financial statements with U.S. generally accepted accounting principles. In reliance on these reviews and discussions, and the report of the independent auditors, the Audit Committee has recommended to the Board of Directors, andthe Board has approved, that the audited financial statements be included in our Annual Report on Form 10-K for the year ended December 31, 2022, for filing with theSecurities and Exchange Commission. Stephen P. Smith, Chairman Galdino J. Claro Richard A. Navarre 78Table of Contents Compensation, Nominating and Governance Committee Executive officer compensation is administered by the CNG Committee, which is currently comprised of three members: Mr. Vecellio, as Chairman, Mr. Navarre andMr. Smith. During 2022, the CNG Committee met 12 times. Our Board of Directors appoints the CNG Committee and delegates to the CNG Committee responsibility for: •reviewing and approving the compensation for our executive officers in light of the time that each executive officer allocates to our business;•reviewing and recommending the annual and long-term incentive plans in which our executive officers participate and approving awards thereunder; and•reviewing and approving compensation for the Board of Directors. Our Board of Directors has determined that each CNG Committee member is independent under the listing standards of the NYSE and the rules of the SEC. Pursuant to its charter, the CNG Committee is authorized to obtain at NRP’s expense compensation surveys, reports on the design and implementation ofcompensation programs for directors and executive officers and other data that the CNG Committee considers as appropriate. In addition, the CNG Committee has thesole authority to retain and terminate any outside counsel or other experts or consultants engaged to assist it in the evaluation of compensation of our directors andexecutive officers. The CNG Committee Charter is available in print upon request. Partnership Agreement Investors may view our partnership agreement and the amendments to the partnership agreement on our website at www.nrplp.com. The partnership agreement isalso filed with the SEC and is available in print to any unitholder that requests them. Corporate Governance Guidelines and Code of Business Conduct and Ethics We have adopted Corporate Governance Guidelines. We have also adopted a Code of Business Conduct and Ethics that applies to our management, and complieswith Item 406 of Regulation S-K. Our Corporate Governance Guidelines and our Code of Business Conduct and Ethics are available on our website at www.nrplp.comand are available in print upon request. We intend to disclose future amendments to certain provisions of the Code of Business Conduct and Ethics, and waivers of theCode of Business Conduct and Ethics granted to executive officers and directors, on the website within four business days following the date of the amendment orwaiver. NYSE Certification Pursuant to Section 303A of the NYSE Listed Company Manual, in 2022, Corbin J. Robertson, Jr. certified to the NYSE that he was not aware of any violation bythe Partnership of NYSE corporate governance listing standards. Delinquent Section 16(a) Reports The reports on Form 4 filed on February 17, 2022 for each of our directors and executive officers were filed 4 days after the due date. 79Table of Contents ITEM 11. EXECUTIVE COMPENSATION Smaller Reporting Company Status We are a “smaller reporting company,” as such term is defined in the rules promulgated under the Securities Exchange Act of 1934, as amended, and we haveelected to provide our executive compensation disclosure in accordance with such rules. Accordingly, we have provided compensation disclosure for our principalexecutive officer and the two most highly compensated executive officers other than our principal executive officer and have omitted the compensation discussion andanalysis and the compensation committee reports as permitted by the rules. Summary Compensation Table Our named executive officers are based in Houston, Texas and employed by Quintana Minerals Corporation (“Quintana”). Quintana is controlled by our Chairmanand Chief Executive Officer and is an affiliate of NRP. The following table sets forth the amounts reimbursed to Quintana for our named executive officers’ compensationfor the years ended December 31, 2022 and 2021: Stock All Other Name and Principal PositionYear Salary ($) Bonus ($) Awards ($) (1) Compensation($) (2) Total ($) Corbin J. Robertson, Jr.—Chief Executive Officer 2022 — 2,379,068 3,096,757 — 5,475,825 2021 — 2,037,340 946,909 — 2,984,249 Craig W. Nunez—President and Chief Operating Officer 2022 530,450 1,034,378 1,683,020 18,300 3,266,148 2021 515,000 885,800 717,032 17,400 2,135,232 Christopher J. Zolas—Chief Financial Officer 2022 375,950 586,482 709,414 18,300 1,690,146 2021 365,000 502,240 412,549 17,400 1,297,189 (1)Amounts represent the grant date fair value of phantom unit awards determined in accordance with Accounting Standards Codification Topic 718 determinedwithout regard to forfeitures. For information regarding the assumptions used in calculating these amounts, see "Item 8. Financial Statements and SupplementaryData—Note 16. Unit-Based Compensation" elsewhere in this Annual Report on Form 10-K for more information.(2)Amounts represent the 401(k) matching contributions allocated to Natural Resource Partners by Quintana. 80Table of Contents Narrative to the Summary Compensation Table As a publicly traded partnership, we have a unique employment and compensation structure that is different from that of a typical public corporation. While ournamed executive officers are employed by Quintana, each of them has been appointed to serve as an executive officer of GP Natural Resource Partners LLC (“GP LLC”),the general partner of NRP (GP) LLC (“NRP GP”), the general partner of NRP. For a more detailed description of our structure, see "Items 1. and 2. Business andProperties—Partnership Structure and Management" in this Annual Report on Form 10-K. Base Salaries With the exception of Mr. Robertson, who does not receive a salary for his services as Chief Executive Officer, our named executive officers are paid an annualbase salary by Quintana for services rendered to us by the named executive officers during the fiscal year. We then reimburse Quintana based on the time allocated byeach named executive officer to our business. The base salaries of our named executive officers are reviewed on an annual basis as well as at the time of a promotion orother material change in responsibilities. Short-Term Cash Incentive Compensation Each named executive officer received a discretionary short-term cash incentive award approved in February 2022 by the CNG Committee. With respect to 2022, theCNG Committee, using recommendations from its independent compensation consultant, NFP Compensation Consultants, determined that cash bonuses would be paidbased on a percentage of base salary. In addition, the CNG Committee determined that it would consider certain criteria to determine bonus amounts, but that the criteriautilized at the time of determination, as well as the relative weight of those criteria, would be discretionary and subject to change based on developments at thePartnership. Long-Term Incentive Compensation Each named executive officer received a discretionary long-term equity incentive award in 2022 under the 2017 Plan. The 2022 awards were made pursuant to aPhantom Unit Award Agreement. We refer to these phantom units issued in 2022 as "2017 Plan Phantom Units" The 2017 Plan Phantom Units time-vest ratably over athree-year period following the grant date. Upon vesting, the award recipient will be issued one common unit of NRP for each phantom unit that vests. The 2017 PlanPhantom Units will also accrue tandem distribution equivalent rights (“DERs”) that will paid to the recipient upon vesting. The 2017 Plan Phantom Units are subject toforfeiture and will vest on an accelerated basis following death or disability of the award recipient, following a change in control of NRP or termination without cause orfor good reason. The grant date fair value of the 2017 Plan Phantom Units awarded in 2022 are disclosed in the Summary Compensation Table under the Stock Awardscolumn. In determining the award amounts The CNG Committee used certain key metrics, are subject to change for future awards based on developments at thePartnership. Perquisites and Other Personal Benefits Quintana maintains employee benefit plans that provide our named executive officers and other employees with the opportunity to enroll in health, dental and lifeinsurance plans. Each of these benefit plans requires the employee to pay a portion of the health and dental premiums, with Quintana paying the remainder. Thesebenefits are offered on the same basis to all employees of Quintana, and the company costs are reimbursed by us to the extent the employee allocates time to ourbusiness. In 2022, Quintana maintained a tax-qualified 401(k) plan. During 2022, Quintana matched 100% of the first 6.0% of the employee contributions under the 401(k) plan.As with the other contributions, any amounts contributed by Quintana are reimbursed by us based on the time allocated by the employee to our business. Neither NRPnor Quintana maintains a pension plan or a defined benefit retirement plan. Employment Agreements Contracts and Potential Payments Upon a Termination of Employment or a Change in Control None of our named executive officers have an employment agreement. All phantom units awarded under the 2017 Plan to date will vest upon a change in control ofNRP and upon the death or disability of the named executive officer. Phantom units awarded in 2021 and 2022 will also vest upon termination of employment of thenamed executive officer without “cause” or for “good reason.” 81Table of Contents Outstanding Equity Awards at December 31, 2022 Awards made to our named executive officers under the 2017 Plan have been made in phantom units that settle in common units on a one-for-one basis withtandem distribution equivalent rights (“DERs”). The phantom unit awards made in 2020, 2021 and 2022 time-vest ratably over the three-year period following the grantdate and accrue DERs to be paid in cash upon each settlement. The table below shows the total number of outstanding phantom unit awards under the 2017 Plan heldby each named executive officer at December 31, 2022: Named Executive Officer Unvested 2017 Plan Phantom Units Market Value of Unvested 2017 Plan PhantomUnits (1) Corbin J. Robertson, Jr. 144,155(2) $7,831,941 Craig W. Nunez 86,141(3) 4,680,041 Christopher J. Zolas 40,552(4) 2,203,190 (1)Based on a unit price of $54.33, the closing price for the common units on December 31, 2022.(2)69,768 phantom units vesting in February 2023, 46,311 phantom units vesting in February 2024 and 28,076 phantom units vesting in February 2025.(3)41,816 phantom units vesting in February 2023, 29,066 phantom units vesting in February 2024 and 15,259 phantom units vesting in February 2025.(4)19,743 phantom units vesting in February 2023, 14,377 phantom units vesting in February 2024 and 6,432 phantom units vesting in February 2025. Directors' Compensation for the Year Ended December 31, 2022 For more information regarding the Board and committees thereof, see “Item 10. Directors and Executive Officers of the Managing General Partner and CorporateGovernance” elsewhere in this Annual Report on Form 10-K. Director compensation during 2022 consisted of a $75,000 cash retainer and an award of phantom unitsunder the 2017 Plan. The phantom units awarded to Board members in 2022 vest after one year; however, the Board members had the option in advance of receipt of theaward to elect to defer settlement of the award until after 90 days following such director’s retirement or earlier departure from the Board. In addition, members of Boardcommittees received $5,000 for each committee served on, and the chairman of the audit, compensation, nominating and governance and conflicts committees receivedan additional $20,000, $15,000 and $10,000, respectively, for acting as chairman. The table below shows the directors’ compensation for the year ended December 31, 2022: Name of Director Fees Earned or Paid in Cash 2017 Plan Common Unit Awards(1) Total Compensation S. Reed Morian $75,000 $104,149 $179,149 Richard A. Navarre (2) 100,000 104,149 204,149 Corbin J. Robertson, III 75,000 104,149 179,149 Stephen P. Smith (3) 105,000 104,149 209,149 Leo A. Vecellio, Jr. 100,000 104,149 204,149 Paul B. Murphy, Jr. 75,000 104,149 179,149 Galdino J. Claro 85,000 104,149 189,149 Alexander D. Greene (4) — — — (1)Amounts represent the grant date fair value of phantom unit awards determined in accordance with Accounting Standards Codification Topic 718 determinedwithout regard to forfeitures. For information regarding the assumptions used in calculating these amounts, see Note 16 to the audited consolidated financialstatements included elsewhere in this Annual Report on Form 10-K. All of the phantom units reported in this column were outstanding on December 31, 2022, andwill vest on February 9, 2023.(2)Mr. Navarre elected to defer settlement of his common units awarded under the 2017 Plan in 2018 and 2019 until 90 days following his retirement or earlier departurefrom the Board. As of December 31, 2022, 7,074 phantom units previously awarded to Mr. Navarre were outstanding but only 2,720 were unvested.(3)Mr. Smith elected to defer settlement of his common units awarded under the 2017 Plan in 2018, 2019, 2020, 2021 and 2022 until 90 days following his retirement orearlier departure from the Board. As of December 31, 2022, 18,082 phantom units previously awarded to Mr. Smith were outstanding but only 2,720 were unvested.(4)Mr. Greene did not receive Board compensation as the Blackstone designee to the Board. 82Table of Contents ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following tables set forth, as of February 16, 2023, the amount and percentage of our common units and preferred units beneficially held by (1) each personknown to us to beneficially own 5% or more of any class of our units, (2) by each of our directors and named executive officers and (3) by all directors and executiveofficers as a group. Unless otherwise noted, each of the named persons and members of the group has sole voting and investment power with respect to the unitsshown. Percentage of Common Common Name of Beneficial Owner Units Units (1) Corbin J. Robertson, Jr. (2) 2,524,453 20.0%Western Pocahontas Corporation (3) 1,739,007 13.8%Western Pocahontas Properties Limited Partnership (4) 1,727,986 13.7%JPMorgan Chase & Co. (5) 1,028,409 8.1%The Goldman Sachs Group, Inc. (6) 1,140,691 9.0%Craig W. Nunez 62,740 * Christopher J. Zolas 28,169 * Galdino J. Claro 17,842 * Alexander D. Greene — — S. Reed Morian (7) 634,241 5.0%Paul B. Murphy, Jr. 17,535 * Richard A. Navarre (8) 14,728 * Corbin J. Robertson III (9) 252,384 2.0%Stephen P. Smith (10) 355 * Leo A. Vecellio, Jr. 20,082 * Directors and Officers as a Group (11) 3,624,225 28.7% *Less than one percent. (1)12,634,642 common units issued and outstanding as of February 16, 2023.(2)Mr. Robertson, Jr. may be deemed to beneficially own 618,919 common units owned in his individual capacity, 1,739,007 common units in his capacity as controllingshareholder of Western Pocahontas Corporation, 156,000 common units in his capacity as the sole member of Robertson Coal Management LLC, which is the solemember of GP Natural Resource Partners, which is the general partner of NRP (GP) LP, 5,293 common units in his capacity as controlling shareholder of GNPManagement Corporation and 5,234 common units held by his spouse, Barbara M. Robertson. Mr. Robertson, Jr.’s address is 1415 Louisiana Street, Suite 2400,Houston, Texas 77002.(3)Western Pocahontas Corporation has sole voting and sole dispositive power with respect to 11,021 common units and shared voting and shared dispositive powerwith respect to 1,727,986 common units in its capacity as the general partner of Western Pocahontas Properties Limited Partnership. The business address ofWestern Pocahontas Corporation is 5260 Irwin Road, Huntington, West Virginia 25705.(4)Western Pocahontas Properties Limited Partnership has sole voting and sole dispositive power with respect to 0 common units and shared voting and shareddispositive power with respect to 1,727,986 common units. The business address of Western Pocahontas Properties Limited Partnership is 5260 Irwin Road,Huntington, West Virginia 25705.(5)According to a Schedule 13G filing with the SEC on January 31, 2023, JPMorgan Chase & Co. holds sole voting power and sole dispositive power with respect to1,028,409 common units. The business address of JPMorgan Chase & Co. is 383 Madison Avenue., New York, NY 10179.(6)According to a Schedule 13G filing with the SEC on February 8, 2023, The Goldman Sachs Group holds shared voting power and shared dispositive power withrespect to 1,140,691 common units in the Partnership. The business address of The Goldman Sachs Group is 200 West Street, New York, NY 10282.(7)Mr. Morian may be deemed to beneficially own 344,863 common units owned by Shadder Investments and 60,097 common units owned by Mocol Properties.(8)Does not include 4,354 common units awarded pursuant to NRP’s long-term incentive plan that Mr. Navarre has elected to defer settlement of until 90 daysfollowing the date that he no longer serves on NRP’s board.(9)Mr. Robertson III may be deemed to beneficially own 9,783 common units held by CIII Capital Management, LLC, 10,000 common units held by BHJ Investments,19,663 common units held by The Corbin James Robertson III 2009 Family Trust and 39 common units held by his spouse, Brooke Robertson. The address for CIIICapital Management, LLC is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002, the address for BHJ Investments is 1415 Louisiana Street, Suite 2400,Houston, Texas 77002 and the address for The Corbin James Robertson III 2009 Family Trust is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002. Thefollowing common units are pledged as collateral for loans: 68,873 common units owned by Mr. Robertson III.(10)Does not include 18,082 common units awarded pursuant to NRP’s long-term incentive plan that Mr. Smith has elected to defer settlement of until 90 days followingthe date that he no longer serves on NRP’s board. Mr. Smith may be deemed to beneficially own 355 common units owned by the SP Smith 2002 Revocable Trust.(11)NRP’s directors and executive officers as a group consists of 14 individuals. 83Table of Contents Percentage of Name of Beneficial Owner Preferred Units Preferred Units Blackstone Inc. (1) 95,001 47%GoldenTree Asset Management, LP (2) 107,500 53% (1)The preferred units are owned by funds managed by Blackstone Inc., whose address is 345 Park Ave, New York, NY 10154. Blackstone Inc. is controlled by itsfounder, Stephen A. Schwarzman.(2)The preferred units are owned by funds managed by GoldenTree Asset Management, LP, whose address is 300 Park Ave, New York, NY 10022. Steven A.Tananbaum serves as senior managing member of GoldenTree Asset Management LLC, the general partner of GoldenTree Asset Management, LP. Securities Authorized for Issuance under Equity Compensation Plans The following table shows the securities authorized for issuance under our 2017 Long-Term Incentive Plan at December 31, 2022. The initial number of commonunits authorized for issuance pursuant to awards under the plan was 800,000 and in March 2022, an additional 800,000 units were authorized for issuance. Number of securities to beissued upon exercise ofoutstanding options, warrantsand rights Weighted-average exercise priceof outstanding options, warrantsand rights Number of securities remainingavailable for future issuanceunder equity compensationplans (excluding securitiesreflected in column (a)) Plan Category (a) (b) (c) Equity compensation plans approved by security holders — — 940,086(1) Equity compensation plans not approved by security holders n/a n/a n/a Total — — 940,086 (1)As of December 31, 2022, 385,936 phantom units were outstanding under the plan. Each phantom unit represents the right to receive one common unit, togetherwith associated distribution equivalent rights. 84Table of Contents ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE Relationships with Entities Associated with Corbin J. Robertson, Jr. Western Pocahontas Properties Limited Partnership, New Gauley Coal Corporation, and Great Northern Properties Limited Partnership are three privately heldcompanies that are primarily engaged in owning and managing mineral properties. We refer to these companies collectively as the WPP Group. Corbin J. Robertson, Jr.owns the general partner of Western Pocahontas Properties, 85% of the general partner of Great Northern Properties Limited Partnership and is the Chairman and ChiefExecutive Officer of New Gauley Coal Corporation. Omnibus Agreement As part of the omnibus agreement entered into concurrently with the closing of our initial public offering, the WPP Group and any entity controlled by Corbin J.Robertson, Jr., which we refer to in this section as the “GP affiliates,” each agreed that neither they nor their affiliates will, directly or indirectly, engage or invest inentities that engage in the following activities (each, a "restricted business") in the specific circumstances described below:•the entering into or holding of leases with a party other than an affiliate of the GP affiliate for any GP affiliate-owned fee coal within the United States; and•the entering into or holding of subleases with a party other than an affiliate of the GP affiliate for coal within the United States controlled by a paid-up lease ownedby any GP affiliate or its affiliate. "Affiliate" means, with respect to any GP affiliate or, any other entity in which such GP affiliate owns, through one or more intermediaries, 50% or more of the thenoutstanding voting securities or other ownership interests of such entity. Except as described below, the WPP Group and their respective controlled affiliates will not beprohibited from engaging in activities in which they compete directly with us. A GP affiliate may, directly or indirectly, engage in a restricted business if:•the GP affiliate was engaged in the restricted business at the closing of the offering; provided that if the fair market value of the asset or group of related assets ofthe restricted business subsequently exceeds $10 million, the GP affiliate must offer the restricted business to us under the offer procedures described below.•the asset or group of related assets of the restricted business have a fair market value of $10 million or less; provided that if the fair market value of the assets of therestricted business subsequently exceeds $10 million, the GP affiliate must offer the restricted business to us under the offer procedures described below.•the asset or group of related assets of the restricted business have a fair market value of more than $10 million and the general partner (with the approval of theconflicts committee) has elected not to cause us to purchase these assets under the procedures described below.•its ownership in the restricted business consists solely of a non-controlling equity interest. For purposes of this paragraph, "fair market value" means the fair market value as determined in good faith by the relevant GP affiliate. The total fair market value in the good faith opinion of the WPP Group of all restricted businesses engaged in by the WPP Group, other than those engaged in bythe WPP Group at closing of our initial public offering (and except as described below under "—Pocahontas Royalties LLC"), may not exceed $75 million. For purposesof this restriction, the fair market value of any entity engaging in a restricted business purchased by the WPP Group will be determined based on the fair market value ofthe entity as a whole, without regard for any lesser ownership interest to be acquired. If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a fair market value in excess of $10 million and therestricted business constitutes greater than 50% of the value of the business to be acquired, then the WPP Group must first offer us the opportunity to purchase therestricted business. If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a value in excess of $10 million andthe restricted business constitutes 50% or less of the value of the business to be acquired, then the GP affiliate may purchase the restricted business first and then offerus the opportunity to purchase the restricted business within six months of acquisition. For purposes of this paragraph, "restricted business" excludes a general partner interest or managing member interest, which is addressed in a separate restrictionsummarized below. For purposes of this paragraph only, "fair market value" means the fair market value as determined in good faith by the relevant GP affiliate. If we want to purchase the restricted business and the GP affiliate and the general partner, with the approval of the conflicts committee, agree on the fair marketvalue and other terms of the offer within 60 days after the general partner receives the offer from the GP affiliate, we will purchase the restricted business as soon ascommercially practicable. If the GP affiliate and the general partner, with the approval of the conflicts committee, are unable to agree in good faith on the fair market valueand other terms of the offer within 60 days after the general partner receives the offer, then the GP affiliate may sell the restricted business to a third party within twoyears for no less than the purchase price and on terms no less favorable to the GP affiliate than last offered by us. During this two-year period, the GP affiliate mayoperate the restricted business in competition with us, subject to the restriction on total fair market value of restricted businesses owned in the case of the WPP Group. 85Table of Contents If, at the end of the two-year period, the restricted business has not been sold to a third party and the restricted business retains a value, in the good faith opinionof the relevant GP affiliate, in excess of $10 million, then the GP affiliate must reoffer the restricted business to the general partner. If the GP affiliate and the generalpartner, with the approval of the conflicts committee, agree on the fair market value and other terms of the offer within 60 days after the general partner receives thesecond offer from the GP affiliate, we will purchase the restricted business as soon as commercially practicable. If the GP Affiliate and the general partner, with theconcurrence of the conflicts committee, again fail to agree after negotiation in good faith on the fair market value of the restricted business, then the GP affiliate will beunder no further obligation to us with respect to the restricted business, subject to the restriction on total fair market value of restricted businesses owned. In addition, if during the two-year period described above, a change occurs in the restricted business that, in the good faith opinion of the GP affiliate, affects thefair market value of the restricted business by more than 10 percent and the fair market value of the restricted business remains, in the good faith opinion of the relevantGP affiliate, in excess of $10 million, the GP affiliate will be obligated to reoffer the restricted business to the general partner at the new fair market value, and the offerprocedures described above will recommence. If the restricted business to be acquired is in the form of a general partner interest in a publicly held partnership or a managing member interest in a publicly heldlimited liability company, the WPP Group may not acquire such restricted business even if we decline to purchase the restricted business. If the restricted business to beacquired is in the form of a general partner interest in a non-publicly held partnership or a managing member of a non-publicly held limited liability company, the WPPGroup may acquire such restricted business subject to the restriction on total fair market value of restricted businesses owned and the offer procedures describedabove. The omnibus agreement may be amended at any time by the general partner, with the concurrence of the conflicts committee. The respective obligations of theWPP Group under the omnibus agreement terminate when the WPP Group and its affiliates cease to participate in the control of the general partner. Pocahontas Royalties LLC On February 28, 2020, Pocahontas Royalties LLC (“Pocahontas Royalties”) completed the acquisition of a private company that owns approximately one millionacres of mineral rights and leases coal to coal mine operators in Central Appalachia. Pocahontas Royalties is controlled by Corbin J. Robertson, Jr. and members of hisfamily. Reed Morian, one of the directors of GP Natural Resource Partners LLC, also serves on the Board of Managers of Pocahontas Royalties. In connection with the closing of the acquisition, we and Pocahontas Royalties entered into a limited waiver of the omnibus agreement pursuant to which wewaived the provision of the omnibus agreement that restricts Mr. Robertson and his affiliates (other than NRP) from owning, operating or investing in fee coal in theUnited States with an aggregate fair market value in excess of $75 million. Mr. Robertson had previously offered NRP the opportunity to participate in the acquisition andwe determined, after due consideration, not to participate. In addition, on February 28, 2020, we and Pocahontas Royalties entered into a right of first offer agreement pursuant to which Pocahontas Royalties granted usthe exclusive right of first offer to purchase any assets (or entities holding such assets) proposed to be sold at any time by Pocahontas Royalties or any of itssubsidiaries with a fair market value exceeding $2 million (individually or in the aggregate), excluding surface acreage, assets or rights (other than surface rights that areappurtenant to or necessary for the development of mineral rights). Provided that Pocahontas Royalties has provided us the opportunity to make a first offer within thetime periods specified in the agreement, Pocahontas Royalties will be under no obligation to accept any offer timely made by us and may determine, in its sole discretion,to consummate a transaction with a third party free and clear of any obligations to us. Quintana Capital Group GP, Ltd. Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd., which controls several private equity funds focused on investments in the energybusiness. NRP’s Board of Directors has adopted a formal conflicts policy that establishes the opportunities that will be pursued by NRP and those that will be pursuedby Quintana Capital. The basic tenets of the policy are set forth below. NRP’s business strategy has historically focused on:•The ownership of natural resource properties in North America, including, but not limited to coal, aggregates and industrial minerals, and oil and gas. NRP leasesthese properties to mining or operating companies that mine or produce the resources and pay NRP a royalty.•The ownership and operation of transportation, storage and related logistics activities related to extracted hard minerals. The businesses and investments described in this paragraph are referred to as the "NRP Businesses." NRP’s acquisition strategy also includes:•The ownership of non-operating working interests in oil and gas properties.•The ownership of non-controlling equity interests in companies involved in natural resource development and extraction.•The operation of construction aggregates mining and production businesses. The businesses and investments described in this paragraph are referred to as the "Shared Businesses." NRP’s business strategy does not, and is not expected to, include:•The ownership of equity interests in companies involved in the mining or extraction of coal.•Investments that do not generate "qualifying income" for a publicly traded partnership under U.S. tax regulations.•Investments outside of North America.•Midstream or refining businesses that do not involve hard extracted minerals, including the gathering, processing, fractionation, refining, storage or transportationof oil, natural gas or natural gas liquids. 86Table of Contents The businesses and investments described in this paragraph are referred to as the "Non-NRP Businesses." It is acknowledged that neither Quintana Capital nor Mr. Robertson will have any obligation to offer investments relating to Non-NRP Businesses to NRP, and thatNRP will not have any obligation to refrain from pursuing a Non-NRP Business if there is a change in its business strategy. For so long as Corbin Robertson, Jr. remains both an affiliate of Quintana Capital and an executive officer or director of NRP or an affiliate of its general partner,before making an investment in an NRP Business, Quintana Capital has agreed to adhere to the following procedures:•Quintana Capital will first offer such opportunity in its entirety to NRP. NRP may elect to pursue such investment wholly for its own account, to pursue theopportunity jointly with Quintana Capital or not to pursue such opportunity.•If NRP elects not to pursue an NRP Business investment opportunity, Quintana Capital may pursue the investment for its own account on similar terms.•NRP will undertake to advise Quintana Capital of its decision regarding a potential investment opportunity within 10 business days of the identification of suchopportunity to the Conflicts Committee. If the opportunity relates to the acquisition of a Shared Business, NRP and Quintana Capital will adhere to the following procedures:•If the opportunity is generated by individuals other than Mr. Robertson, the opportunity will belong to the entity for which those individuals are working.•If the opportunity is generated by Mr. Robertson and both NRP and Quintana Capital are interested in pursuing the opportunity, it is expected that the ConflictsCommittee will work together with the relevant Limited Partner Advisory Committees for Quintana Capital to reach an equitable resolution of the conflict, which mayinvolve investments by both parties. In all cases above in which Mr. Robertson has a conflict of interest, investment decisions will be made on behalf of NRP by the Conflicts Committee and on behalfof Quintana Capital Group by the relevant Investment Committee, with Mr. Robertson abstaining. Relationships with Entities Associated with Corbin J. Robertson, III Quinwood Coal Partners LP (“Quinwood”), an entity controlled by Corbin J. Robertson, III leases two coal properties from us in Central Appalachia. During theyears ended December 31, 2022 and 2021, we recorded $0.0 million in coal royalty revenues from Quinwood and received $0.0 million and less than $0.1 million in cashrelated to royalty and property tax payments, respectively. Preferred Unitholder Board Representation and Observation Rights Agreement Effective on March 2, 2017, in connection with the closing of the issuance of the Preferred Units, we entered into the Board Observation and RepresentationRights Agreement (the “Board Rights Agreement”) with Blackstone and GoldenTree. Pursuant to the Board Rights Agreement, Blackstone appoints one member toserve on the Board of Directors of GP Natural Resource Partners LLC and also appoints one observer to attend meetings of the Board. Blackstone's rights to appoint amember of the Board and an observer will terminate at such time as Blackstone, together with their affiliates, no longer own at least 20% of the total number of PreferredUnits issued on the closing date, together with all PIK Units that have been issued but not redeemed (the "Minimum Preferred Unit Threshold"). Following the time thatBlackstone (and their affiliates) no longer own the Minimum Preferred Unit Threshold and until such time as GoldenTree (together with their affiliates) no longer own theMinimum Preferred Unit Threshold, GoldenTree shall have the one-time option to appoint either one person to serve as a member of the Board or one person to serve asa Board observer. To the extent GoldenTree elects to appoint a Board member and later remove such Board member, GoldenTree may then elect to appoint a Boardobserver. For more information on the Preferred Units, including the rights of the holders thereof, see "Item 8. Financial Statements and Supplementary Data—Note 4.Class A Convertible Preferred Units and Warrants" elsewhere in this Annual Report on Form 10-K. Office Building in Huntington, West Virginia We lease an office building in Huntington, West Virginia from Western Pocahontas Properties Limited Partnership. The initial 10-year term of the lease expired atthe end of 2018. On January 1, 2019, we entered into a new lease on the building for a five-year base term, with five additional five-year renewal options. We paidapproximately $0.8 million to Western Pocahontas under the lease during both years ended December 31, 2022 and 2021. Relationship with Cadence Bank, N.A. Paul B. Murphy, Jr. one of the members of the Board of Directors of GP Natural Resource Partners LLC, is the Chairman of Cadence Bank, N.A., which is a lenderunder NRP Operating’s revolving credit facility and has received customary fees and interest payments in connection therewith. We paid approximately $0.3 millionand $0.1 million in interest and fees under the credit facility to Cadence Bank, N.A during the years ended December 31, 2022 and 2021, respectively. 87Table of Contents Conflicts of Interest Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including the WPP Group andPocahontas Royalties) on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of GP Natural Resource Partners LLChave duties to manage GP Natural Resource Partners LLC and our general partner in a manner beneficial to its owners. At the same time, our general partner has a dutyto manage our partnership in a manner beneficial to us and our unitholders. The Delaware Revised Uniform Limited Partnership Act, which we refer to as the DelawareAct, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a generalpartner to limited partners and the partnership. Pursuant to these provisions, our partnership agreement contains various provisions modifying the fiduciary duties thatwould otherwise be owed by our general partner with contractual standards governing the duties of the general partner and the methods of resolving conflicts ofinterest. Our partnership agreement also specifically defines the remedies available to limited partners for actions taken that, without these defined liability standards,might constitute breaches of fiduciary duty under applicable Delaware law. Whenever a conflict arises between our general partner or its affiliates, on the one hand, and our partnership or any other partner, on the other, our general partnerwill resolve that conflict. Our general partner may, but is not required to, seek the approval of the conflicts committee of the Board of Directors of our general partner ofsuch resolution. The partnership agreement contains provisions that allow our general partner to take into account the interests of other parties in addition to ourinterests when resolving conflicts of interest. Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict isconsidered to be fair and reasonable to us. Any resolution is considered to be fair and reasonable to us if that resolution is:•approved by the conflicts committee, although our general partner is not obligated to seek such approval and our general partner may adopt a resolution or courseof action that has not received approval;•on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or•fair to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable oradvantageous to us. In resolving a conflict, our general partner, including its conflicts committee, may, unless the resolution is specifically provided for in the partnership agreement,consider:•the relative interests of any party to such conflict and the benefits and burdens relating to such interest;•any customary or accepted industry practices or historical dealings with a particular person or entity;•generally accepted accounting practices or principles; and•such additional factors it determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances. Blackstone has certain consent rights and board appointment and observation rights and may be deemed to be an affiliate of our general partner. In addition,GoldenTree has certain limited consent rights. In the exercise of these consent rights and board rights, conflicts of interest could arise between us on the one hand, andBlackstone or GoldenTree on the other hand. Conflicts of interest could arise in the situations described below, among others. Actions taken by our general partner may affect the amount of cash available for distribution to unitholders. The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:•amount and timing of asset purchases and sales;•cash expenditures;•borrowings;•the issuance of additional common units; and•the creation, reduction or increase of mineral rights in any quarter. In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to the unitholders, including borrowings thathave the purpose or effect of enabling our general partner to receive distributions. For example, in the event we have not generated sufficient cash from our operations to pay the quarterly distribution on our common units, our partnershipagreement permits us to borrow funds which may enable us to make this distribution on all outstanding common units. The partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliatesmay not borrow funds from us or our subsidiaries. 88Table of Contents We do not have any officers or employees. We rely on officers and employees of GP Natural Resource Partners LLC and its affiliates. We do not have any officers or employees and rely on officers and employees of GP Natural Resource Partners LLC and its affiliates. Affiliates of GP NaturalResource Partners LLC conduct businesses and activities of their own in which we have no economic interest. If these separate activities are significantly greater thanour activities, there could be material competition for the time and effort of the officers and employees who provide services to our general partner. The officers of GPNatural Resource Partners LLC are not required to work full time on our affairs. Certain of these officers devote significant time to the affairs of the WPP Group or itsaffiliates and are compensated by these affiliates for the services rendered to them. We reimburse our general partner and its affiliates for expenses. We reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff andsupport services to us. The partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable mannerdetermined by our general partner in its sole discretion. Our general partner intends to limit its liability regarding our obligations. Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our generalpartner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability or our liability is not a breach of our generalpartner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us. Any agreements between us on the one hand, and our general partner and its affiliates, on the other, do not grant to the unitholders, separate and apart from us,the right to enforce the obligations of our general partner and its affiliates in our favor. Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not the result of arm’s-length negotiations. The partnership agreement allows our general partner to pay itself or its affiliates for any services rendered to us, provided these services are rendered on termsthat are fair and reasonable. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither the partnershipagreement nor any of the other agreements, contracts and arrangements between us, on the one hand, and our general partner and its affiliates, on the other, are theresult of arm’s-length negotiations. All of these transactions entered into after our initial public offerings are on terms that are fair and reasonable to us. Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may beprovided in contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind. We may not choose to retain separate counsel for ourselves or for the holders of common units. The attorneys, independent auditors and others who have performed services for us in the past were retained by our general partner, its affiliates and us and havecontinued to be retained by our general partner, its affiliates and us. Attorneys, independent auditors and others who perform services for us are selected by our generalpartner or the conflicts committee and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders ofcommon units in the event of a conflict of interest arising between our general partner and its affiliates, on the one hand, and us or the holders of common units, on theother, depending on the nature of the conflict. We do not intend to do so in most cases. Delaware case law has not definitively established the limits on the ability of apartnership agreement to restrict such fiduciary duties. Our general partner’s affiliates may compete with us. The partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership ofinterests in us. Except as provided in our partnership agreement and the Omnibus Agreement, affiliates of our general partner will not be prohibited from engaging inactivities in which they compete directly with us. The Conflicts Committee Charter is available upon request. Director Independence For a discussion of the independence of the members of the Board of Directors of our managing general partner under applicable standards, see "Item 10.Directors and Executive Officers of the Managing General Partner and Corporate Governance—Corporate Governance—Independence of Directors," which isincorporated by reference into this Item 13. Review, Approval or Ratification of Transactions with Related Persons If a conflict or potential conflict of interest arises between our general partner and its affiliates (including the WPP Group and Pocahontas Royalties) on the onehand, and our partnership and our limited partners, on the other hand, the resolution of any such conflict or potential conflict is addressed as described under "—Conflicts of Interest." Pursuant to our Code of Business Conduct and Ethics, conflicts of interest are prohibited as a matter of policy, except under guidelines approved by the Boardand as provided in the Omnibus Agreement and our partnership agreement. For the year ended December 31, 2022 there were no transactions where such guidelineswere not followed. 89Table of Contents ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The Audit Committee of the Board of Directors of GP Natural Resource Partners LLC recommended, and we engaged Ernst & Young LLP to audit our accounts andassist with tax compliance for fiscal 2022 and 2021. All of our audit, audit-related fees and tax services have been approved by the Audit Committee of our Board ofDirectors. The following table presents fees for professional services rendered by Ernst & Young LLP: 2022 2021 Audit Fees (1) $904,137 $757,450 Tax Fees (2) 437,400 412,500 (1)Audit fees include fees associated with the annual integrated audit of our consolidated financial statements and internal controls over financial reporting, separateaudits of subsidiaries and reviews of our quarterly financial statement for inclusion in our Form 10-Q and comfort letters; consents; work related to acquisitions;assistance with and review of documents filed with the SEC.(2)Tax fees include fees principally incurred for assistance with tax planning, compliance, tax return preparation and filing of Schedules K-1. Audit and Non-Audit Services Pre-Approval Policy I. Statement of Principles Under the Sarbanes-Oxley Act of 2002 (the "Act"), the Audit Committee of the Board of Directors is responsible for the appointment, compensation and oversightof the work of the independent auditor. As part of this responsibility, the Audit Committee is required to pre-approve the audit and non-audit services performed by theindependent auditor in order to assure that they do not impair the auditor’s independence from the Partnership. To implement these provisions of the Act, the SEC hasissued rules specifying the types of services that an independent auditor may not provide to its audit client, as well as the audit committee’s administration of theengagement of the independent auditor. Accordingly, the Audit Committee has adopted, and the Board of Directors has ratified, this Audit and Non-Audit Services Pre-Approval Policy (the "Policy"), which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the independent auditormay be pre-approved. The SEC’s rules establish two different approaches to pre-approving services, which the SEC considers to be equally valid. Proposed services may either be pre-approved without consideration of specific case-by-case services by the Audit Committee ("general pre-approval") or require the specific pre-approval of the AuditCommittee ("specific pre-approval"). The Audit Committee believes that the combination of these two approaches in this Policy will result in an effective and efficientprocedure to pre-approve services performed by the independent auditor. As set forth in this Policy, unless a type of service has received general pre-approval, it willrequire specific pre-approval by the Audit Committee if it is to be provided by the independent auditor. Any proposed services exceeding pre-approved cost levels orbudgeted amounts will also require specific pre-approval by the Audit Committee. For both types of pre-approval, the Audit Committee will consider whether such services are consistent with the SEC’s rules on auditor independence. The AuditCommittee will also consider whether the independent auditor is best positioned to provide the most effective and efficient service for reasons such as its familiaritywith our business, employees, culture, accounting systems, risk profile and other factors, and whether the service might enhance the Partnership’s ability to manage orcontrol risk or improve audit quality. All such factors will be considered as a whole, and no one factor will necessarily be determinative. The Audit Committee is also mindful of the relationship between fees for audit and non-audit services in deciding whether to pre-approve any such services andmay determine, for each fiscal year, the appropriate ratio between the total amount of fees for audit, audit-related and tax services. The appendices to this Policy describe the audit, audit-related and tax services that have the general pre-approval of the Audit Committee. The term of any generalpre-approval is 12 months from the date of pre-approval, unless the Audit Committee considers a different period and states otherwise. For the audit, pre-approval is forthe fiscal year as the time between approval and the actual issuance of the audit may be more than 12 months. The Audit Committee will annually review and pre-approve the services that may be provided by the independent auditor without obtaining specific pre-approval from the Audit Committee. The Audit Committee will addor subtract to the list of general pre-approved services from time to time, based on subsequent determinations. The purpose of this Policy is to set forth the procedures by which the Audit Committee intends to fulfill its responsibilities. It does not delegate the AuditCommittee’s responsibilities to pre-approve services performed by the independent auditor to management. Ernst & Young LLP, our independent auditor reviews this Policy annually and it does not adversely affect its independence. 90Table of Contents II. Delegation As provided in the Act and the SEC’s rules, the Audit Committee has delegated either type of pre-approval authority to Stephen P. Smith, the Chairman of theAudit Committee. Mr. Smith must report, for informational purposes only, any pre-approval decisions to the Audit Committee at its next scheduled meeting. III. Audit Services The annual Audit services engagement terms and fees will be subject to the specific pre-approval of the Audit Committee. Audit services include the annualfinancial statement audit (including required quarterly reviews), subsidiary audits and other procedures required to be performed by the independent auditor to be ableto form an opinion on the Partnership’s consolidated financial statements. These other procedures include information systems and procedural reviews and testingperformed in order to understand and place reliance on the systems of internal control, and consultations relating to the audit or quarterly review. Audit services alsoinclude the attestation engagement for the independent auditor’s report on internal controls for financial reporting. The Audit Committee monitors the audit servicesengagement as necessary, but not less than on a quarterly basis, and approves, if necessary, any changes in terms, conditions and fees resulting from changes in auditscope, partnership structure or other items. In addition to the annual audit services engagement approved by the Audit Committee, the Audit Committee may grant general pre-approval to other auditservices, which are those services that only the independent auditor reasonably can provide. Other audit services may include statutory audits or financial audits forour subsidiaries or our affiliates and services associated with SEC registration statements, periodic reports and other documents filed with the SEC or other documentsissued in connection with securities offerings. IV. Audit-related Services Audit-related services are assurance and related services that are reasonably related to the performance of the audit or review of the Partnership’s financialstatements or that are traditionally performed by the independent auditor. Because the Audit Committee believes that the provision of audit-related services does notimpair the independence of the auditor and is consistent with the SEC’s rules on auditor independence, the Audit Committee may grant general pre-approval to audit-related services. Audit-related services include, among others, due diligence services pertaining to potential business acquisitions/dispositions; accountingconsultations related to accounting, financial reporting or disclosure matters not classified as "Audit Services"; assistance with understanding and implementing newaccounting and financial reporting guidance from rulemaking authorities; financial audits of employee benefit plans; agreed-upon or expanded audit procedures relatedto accounting and/or billing records required to respond to or comply with financial, accounting or regulatory reporting matters; and assistance with internal controlreporting requirements. V. Tax Services The Audit Committee believes that the independent auditor can provide tax services to the Partnership such as tax compliance, tax planning and tax advicewithout impairing the auditor’s independence, and the SEC has stated that the independent auditor may provide such services. Hence, the Audit Committee believes itmay grant general pre-approval to those tax services that have historically been provided by the auditor, that the Audit Committee has reviewed and believes would notimpair the independence of the auditor and that are consistent with the SEC’s rules on auditor independence. The Audit Committee will not permit the retention of theindependent auditor in connection with a transaction initially recommended by the independent auditor, the sole business purpose of which may be tax avoidance andthe tax treatment of which may not be supported in the Internal Revenue Code and related regulations. The Audit Committee will consult with the Chief Financial Officeror outside counsel to determine that the tax planning and reporting positions are consistent with this Policy. VI. Pre-Approval Fee Levels or Budgeted Amounts Pre-approval fee levels or budgeted amounts for all services to be provided by the independent auditor will be established annually by the Audit Committee. Anyproposed services exceeding these levels or amounts will require specific pre-approval by the Audit Committee. The Audit Committee is mindful of the overallrelationship of fees for audit and non-audit services in determining whether to pre-approve any such services. For each fiscal year, the Audit Committee may determinethe appropriate ratio between the total amount of fees for audit, audit-related and tax services. VII. Procedures All requests or applications for services to be provided by the independent auditor that do not require specific approval by the Audit Committee will be submittedto the Chief Financial Officer and must include a detailed description of the services to be rendered. The Chief Financial Officer will determine whether such services areincluded within the list of services that have received the general pre-approval of the Audit Committee. The Audit Committee will be informed on a timely basis of anysuch services rendered by the independent auditor. Requests or applications to provide services that require specific approval by the Audit Committee will be submitted to the Audit Committee by both theindependent auditor and the Chief Financial Officer, and must include a joint statement as to whether, in their view, the request or application is consistent with theSEC’s rules on auditor independence. 91Table of Contents PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (a)(1) and (2) Financial Statements and Schedules See "Item 8. Financial Statements and Supplementary Data." (a)(3) Sisecam Wyoming LLC Financial Statements The financial statements of Sisecam Wyoming LLC required pursuant to Rule 3-09 of Regulation S-X are included in this filing as Exhibit 99.1. (a)(4) Exhibits ExhibitNumberDescription3.1Fifth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of March 2, 2017 (incorporated by referenceto Exhibit 3.1 to Current Report on Form 8-K filed on March 6, 2017).3.2Fifth Amended and Restated Agreement of Limited Partnership of NRP (GP) LP, dated as of December 16, 2011 (incorporated by reference to Exhibit 3.1to Current Report on Form 8-K filed on December 16, 2011).3.3Fifth Amended and Restated Limited Liability Company Agreement of GP Natural Resource Partners LLC, dated as of October 31, 2013 (incorporated byreference to Exhibit 3.1 to Current Report on Form 8-K filed on October 31, 2013).3.4Amended and Restated Limited Liability Company Agreement of NRP (Operating) LLC, dated as of October 17, 2002 (incorporated by reference toExhibit 3.4 of Annual Report on Form 10-K for the year ended December 31, 2002).3.5Certificate of Limited Partnership of Natural Resource Partners L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1filed April 19, 2002, File No. 333-86582).4.1Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the Purchasers signatory thereto (incorporated by reference toExhibit 4.1 to Current Report on Form 8-K filed June 23, 2003).4.2First Amendment, dated as of July 19, 2005, to Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the purchaserssignatory thereto (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed on July 20, 2005).4.3Second Amendment, dated as of March 28, 2007, to Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and thepurchasers signatory thereto (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed on March 29, 2007).4.4First Supplement to Note Purchase Agreement, dated as of July 19, 2005 among NRP (Operating) LLC and the purchasers signatory thereto(incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on July 20, 2005).4.5Second Supplement to Note Purchase Agreement, dated as of March 28, 2007 among NRP (Operating) LLC and the purchasers signatory thereto(incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 29, 2007).4.6Third Supplement to Note Purchase Agreement, dated as of March 25, 2009 among NRP (Operating) LLC and the purchasers signatory thereto(incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 26, 2009).4.7Fourth Supplement to Note Purchase Agreement, dated as of April 20, 2011 among NRP (Operating) LLC and the purchasers signatory thereto(incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on April 21, 2011).4.8Subsidiary Guarantee of Senior Notes of NRP (Operating) LLC, dated June 19, 2003 (incorporated by reference to Exhibit 4.5 to Current Report on Form8-K filed June 23, 2003).4.9Form of Series A Note (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed June 23, 2003).4.10Form of Series D Note (incorporated by reference to Exhibit 4.12 to Annual Report on Form 10-K filed February 28, 2007). 92Table of Contents ExhibitNumberDescription4.11Form of Series E Note (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed March 29, 2007).4.12Form of Series F Note (incorporated by reference to Exhibit 4.2 to Quarterly Report on Form 10-Q filed May 7, 2009).4.13Form of Series G Note (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q filed May 7, 2009).4.14Form of Series H Note (incorporated by reference to Exhibit 4.2 to Quarterly Report on Form 10-Q filed May 5, 2011).4.15Form of Series I Note (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q filed May 5, 2011).4.16Form of Series J Note (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on June 15, 2011).4.17Form of Series K Note (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on October 3, 2011).4.18Registration Rights Agreement, dated as of January 23, 2013, by and among Natural Resource Partners L.P. and the Investors named therein(incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on January 25, 2013).4.19Third Amendment, dated as of June 16, 2015, to Note Purchase Agreements, dated as of June 19, 2003, among NRP (Operating) LLC and the holdersnamed therein (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on June 18, 2015).4.20Fourth Amendment, dated as of September 9, 2016, to Note Purchase Agreements, dated as of June 19, 2003, among NRP (Operating) LLC and theholders named therein (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on September 12, 2016).4.21Indenture, dated April 29, 2019, by and among Natural Resource Partners L.P. and NRP Finance Corporation, as issuers, and Wilmington Trust, NationalAssociation, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on May 2, 2019).4.22Form of 9.125% Senior Notes due 2025 (contained in Exhibit 1 to Exhibit 4.21).4.23Registration Rights Agreement dated as of March 2, 2017, by and among Natural Resource Partners L.P. and the Purchasers named therein(incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed on March 6, 2017).4.24Form of Warrant to Purchase Common Units (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 6, 2017).4.25Description of Equity Securities of Natural Resource Partners L.P. (incorporated by reference to Exhibit 4.25 to Annual Report on Form 10-K filed onFebruary 27, 2020).10.1Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP (Operating) LLC, the lenders party thereto, Citibank,N.A. as Administrative Agent and Collateral Agent, Citigroup Global Markets Inc. and Wells Fargo Securities LLC as Joint Lead Arrangers and JointBookrunners, and Citibank, N.A., as Syndication Agent (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on June 18, 2015).10.2First Amendment, dated as of June 3, 2016, to Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP(Operating) LLC, the lenders party thereto, Citibank, N.A. as Administrative Agent and Collateral Agent, Citigroup Global Markets Inc. and Wells FargoSecurities LLC as Joint Lead Arrangers and Joint Bookrunners, and Citibank, N.A., as Syndication Agent (incorporated by reference to Exhibit 10.1 toCurrent Report on Form 8-K filed on June 7, 2016).10.3First Amended and Restated Omnibus Agreement, dated as of April 22, 2009, by and among Western Pocahontas Properties Limited Partnership, GreatNorthern Properties Limited Partnership, New Gauley Coal Corporation, Robertson Coal Management LLC, GP Natural Resource Partners LLC, NRP (GP)LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q filed May 7,2009).10.4Limited Liability Company Agreement of Sisecam Wyoming LLC, dated June 30, 2014 (incorporated by reference to Exhibit 10.1 to Current Report onForm 8-K filed by Sisecam Resources LP on July 2, 2014).10.5Amendment No. 1 to the Limited Liability Company Agreement of Sisecam Wyoming LLC dated November 5, 2015 (incorporated by reference to Exhibit10.22 to Annual Report on Form 10-K filed by Sisecam Resources LP on March 11, 2016). 93Table of Contents ExhibitNumberDescription10.6Second Amendment, dated as of March 2, 2017, to Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP(Operating) LLC, the lenders party thereto, Citibank, N.A. as Administrative Agent and Collateral Agent, Citigroup Global Markets Inc. and Wells FargoSecurities LLC as Joint Lead Arrangers and Joint Bookrunners, and Citibank, N.A., as Syndication Agent (incorporated by reference to Exhibit 10.3 toCurrent Report on Form 8-K filed on March 6, 2017).10.7Fourth Amendment, dated as of April 3, 2019, to Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP(Operating) LLC and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on April 9, 2019).10.8Master Assignment Agreement and Fifth Amendment to Third Amended Credit Agreement, dated as of August 9, 2022 by and among NRP (Operating)LLC, the Lenders party thereto, the Exiting Lenders, and Zions Bancorporation, N.A. dba Amegy Bank, as administrative agent for the Lenders, asSwingline Lender, and as an Issuing Bank (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on August 11, 2022). 10.9New Lender Agreement, dated as of September 1, 2022 by and among NRP (Operating) LLC, the Borrower, Zions Bancorporation, N.A. dba AmegyBank, in its capacity as administrative agent under the Fifth Amendment to Third Amended Credit Agreement and Prosperity Bank, the New Lender(incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on September 8, 2022). 10.10New Lender Agreement, dated as of April 8, 2019, by and among NRP (Operating) LLC and the lenders party thereto (incorporated by reference toExhibit 10.2 to Current Report on Form 8-K filed on April 9, 2019).10.11Board Representation and Observation Rights Agreement dated as of March 2, 2017, by and among Natural Resource Partners L.P., Robertson CoalManagement LLC, GP Natural Resource Partners LLC, NRP (GP) LP, BTO Carbon Holdings L.P. and the GoldenTree Purchasers named therein(incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on March 6, 2017)10.12Master Amendment and Supplement to Coal Mining and Transportation Lease Agreements and Parent Guaranty dated June 30, 2020 by and amongNRP (Operating) LLC, WPP LLC, Hod LLC, Independence Land Company, LLC, Williamson Transport LLC, Foresight Energy LP, Foresight Energy GPLLC, Foresight Energy LLC, Macoupin Energy, LLC, Williamson Energy, LLC, Sugar Camp Energy, LLC, Hillsboro Energy LLC, Foresight EnergyResources LLC, and Foresight Energy Operating LLC (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on July 1, 2020).10.13Limited Waiver dated February 28, 2020 by Natural Resource Partners L.P., GP Natural Resource Partners LLC, NRP (GP) LP, and NRP (Operating) LLC(incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on March 3, 2020).10.14Right of First Offer Agreement dated as of February 28, 2020 by and among Pocahontas Royalties LLC, Natural Resource Partners L.P., GP NaturalResource Partners LLC, NRP (GP) LP, and NRP (Operating) LLC. (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on March3, 2020).10.15+Natural Resource Partners L.P. 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on January17, 2018).10.16+Form of Phantom Unit Award Agreement (Employees and Service Providers) (incorporated by reference to Exhibit 4.5 to Registration Statement on FormS-8 filed on February 9, 2018).10.17+Form of Phantom Unit Award Agreement (Directors) (incorporated by reference to Exhibit 4.6 to Registration Statement on Form S-8 filed on February 9,2018).10.18+Form of Phantom Unit Award Agreement (Employees and Service Providers) (incorporated by reference to Exhibit 10.13 to Annual Report on Form 10-Kfiled on February 27, 2020).10.19+Form of Phantom Form of Phantom Unit Award Agreement (Directors) (incorporated by reference to Exhibit 10.14 to Annual Report on Form 10-K filedon February 27, 2020).10.20+Form of Phantom Unit Award Agreement (Directors with Deferral Election) (incorporated by reference to Exhibit 10.15 to Annual Report on Form 10-Kfiled on February 27, 2020).21.1*List of Subsidiaries of Natural Resource Partners L.P.23.1*Consent of Ernst & Young LLP.23.2*Consent of BDO USA, LLP.23.3*Consent of Deloitte & Touche LLP.31.1*Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley.31.2*Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley.32.1**Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350.32.2**Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350.99.1*Financial Statements of Sisecam Wyoming LLC as of December 31, 2022 and 2021 and for the years ended December 31, 2022, 2021 and 2020. 94Table of Contents ExhibitNumberDescription101.INS*Inline XBRL Instance Document101.SCH*Inline XBRL Taxonomy Extension Schema Document101.CAL*Inline XBRL Taxonomy Extension Calculation Linkbase Document101.DEF*Inline XBRL Taxonomy Extension Definition Linkbase Document101.LAB*Inline XBRL Taxonomy Extension Labels Linkbase Document101.PRE*Inline XBRL Taxonomy Extension Presentation Linkbase Document104*Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101) *Filed herewith**Furnished herewith+Management compensatory plan or arrangement 95Table of Contents SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf bythe undersigned, thereunto duly authorized. NATURAL RESOURCE PARTNERS L.P. By:NRP (GP) LP, its general partner By:GP NATURAL RESOURCE PARTNERS LLC, its general partner Date: March 2, 2023 By:/s/ CORBIN J. ROBERTSON, JR. Corbin J. Robertson, Jr. Chairman of the Board, Director and Chief Executive Officer (Principal Executive Officer) Date: March 2, 2023 By:/s/ CHRISTOPHER J. ZOLAS Christopher J. Zolas Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer) 96Table of Contents Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and inthe capacities and on the dates indicated. Date: March 2, 2023 /s/ GALDINO J. CLARO Galdino J. Claro Director Date: March 2, 2023 /s/ ALEXANDER D. GREENE Alexander D. Greene Director Date: March 2, 2023 /s/ S. REED MORIAN S. Reed Morian Director Date: March 2, 2023 /s/ PAUL B. MURPHY, JR. Paul B. Murphy, Jr. Director Date: March 2, 2023 /s/ RICHARD A. NAVARRE Richard A. Navarre Director Date: March 2, 2023 /s/ CORBIN J. ROBERTSON III Corbin J. Robertson III Director Date: March 2, 2023 /s/ STEPHEN P. SMITH Stephen P. Smith Director Date: March 2, 2023 /s/ LEO A. VECELLIO, JR. Leo A. Vecellio, Jr. Director 97Exhibit 21.1 List of Subsidiaries of Natural Resource Partners L.P. NRP (Operating) LLCNRP Oil and Gas LLCNRP Finance CorporationWPP LLCACIN LLCWBRD LLCHod LLCShepard Boone Coal Company LLCGatling Mineral, LLCIndependence Land Company, LLCWilliamson Transport, LLCRivervista Mining, LLCNRP Trona LLCBRP LLCBRP Minerals LLCCoVal Leasing Company, LLC Exhibit 23.1 Consent of Independent Registered Public Accounting Firm We consent to the incorporation by reference in the following Registration Statements: 1) Registration Statement (Form S-3 No. 333-217205) of Natural Resource Partners L.P., 2) Registration Statement (Form S-3 No. 333-187883) of Natural Resource Partners L.P., 3) Registration Statement (Form S-3 No. 333-262435) of Natural Resource Partners L.P., and 4) Registration Statement (Form S-8 No. 333-222970) pertaining to the Natural Resource Partners L.P. 2017 Long-Term Incentive Plan; of our reports dated March 2, 2023, with respect to the consolidated financial statements of Natural Resource Partners L.P., and the effectiveness of internal control overfinancial reporting of Natural Resource Partners L.P., included in this Annual Report (Form 10-K) of Natural Resource Partners L.P. for the year ended December 31, 2022. /s/ Ernst & Young LLP Houston, TexasMarch 2, 2023 Exhibit 23.2 Consent of Independent Registered Public Accounting Firm Natural Resource Partners LPHouston, Texas We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-217205, 333-187883, 333-262435) and Form S-8 (No. 333-222970) of Natural Resource Partners LP of our report dated March 2, 2023, relating to the consolidated financial statements of Sisecam Wyoming LLC, which appear inthis Annual Report on Form 10-K of Natural Resource Partners LP. /s/ BDO USA, LLPAtlanta, GeorgiaMarch 2, 2023 Exhibit 23.3 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in Registration Statement Nos. 333-217205, 333-187883, and 333-262435 on Form S-3 and Registration No. 333-222970 onForm S-8 of Natural Resource Partners LP, of our report dated March 15, 2022, relating to the financial statements of Sisecam Wyoming LLC as of December 31, 2021,and for the two years in the period ended December 31, 2021, appearing in this Annual Report on Form 10-K of Natural Resource Partners LP for the year endedDecember 31, 2022. /s/ Deloitte & Touche LLP Atlanta, GeorgiaMarch 2, 2023 Exhibit 31.1 CERTIFICATION OF CHIEF EXECUTIVE OFFICER I, Corbin J. Robertson, Jr., certify that: 1I have reviewed this report on Form 10-K of Natural Resource Partners L.P. 2Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport; 3Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) forthe registrant and have: a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to bedesigned under our supervision, to ensure that material information relating to the registrant, including itsconsolidated subsidiaries, is made known to us by others within those entities, particularly during the period in whichthis report is being prepared; b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to bedesigned under our supervision, to provide reasonable assurance regarding the reliability of financial reporting andthe preparation of financial statements for external purposes in accordance with generally accepted accountingprinciples; c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report ourconclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period coveredby this report based on such evaluation; and d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred duringthe registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that hasmaterially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;and 5The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions); a.All significant deficiencies and material weaknesses in the design or operation of internal control over financialreporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize andreport financial information; and b.Any fraud, whether or not material, that involves management or other employees who have a significant role in theregistrant’s internal control over financial reporting. By:/s/ Corbin J. Robertson, Jr. Corbin J. Robertson, Jr. Chief Executive Officer Date:March 2, 2023 Exhibit 31.2 CERTIFICATION OF CHIEF FINANCIAL OFFICER I, Christopher J. Zolas, certify that: 1.I have reviewed this report on Form 10-K of Natural Resource Partners L.P. 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) forthe registrant and have: a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to bedesigned under our supervision, to ensure that material information relating to the registrant, including itsconsolidated subsidiaries, is made known to us by others within those entities, particularly during the period in whichthis report is being prepared; b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to bedesigned under our supervision, to provide reasonable assurance regarding the reliability of financial reporting andthe preparation of financial statements for external purposes in accordance with generally accepted accountingprinciples; c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report ourconclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period coveredby this report based on such evaluation; and d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred duringthe registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that hasmaterially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;and 5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions); a.All significant deficiencies and material weaknesses in the design or operation of internal control over financialreporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize andreport financial information; and b.Any fraud, whether or not material, that involves management or other employees who have a significant role in theregistrant’s internal control over financial reporting. By:/s/ Christopher J. Zolas Christopher J. Zolas Chief Financial Officer Date:March 2, 2023 Exhibit 32.1 CERTIFICATION OFCHIEF EXECUTIVE OFFICEROF GP NATURAL RESOURCE PARTNERS LLCPURSUANT TO 18 U.S.C. § 1350 In connection with the accompanying report on Form 10-K for the year ended December 31, 2022 filed with the Securities and Exchange Commission on the datehereof (the “Report”), I, Corbin J. Robertson, Jr., Chief Executive Officer of GP Natural Resource Partners LLC, the general partner of the general partner of NaturalResource Partners L.P. (the “Company”), hereby certify, to my knowledge, that: 1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. By:/s/ Corbin J. Robertson, Jr. Corbin J. Robertson, Jr. Chief Executive Officer Date:March 2, 2023 Exhibit 32.2 CERTIFICATION OFCHIEF FINANCIAL OFFICEROF GP NATURAL RESOURCE PARTNERS LLCPURSUANT TO 18 U.S.C. § 1350 In connection with the accompanying report on Form 10-K for the year ended December 31, 2022 filed with the Securities and Exchange Commission on the datehereof (the “Report”), I, Christopher J. Zolas, Chief Financial Officer of GP Natural Resource Partners LLC, the general partner of the general partner of Natural ResourcePartners L.P. (the “Company”), hereby certify, to my knowledge, that: 1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. By:/s/ Christopher J. Zolas Christopher J. Zolas Chief Financial Officer Date:March 2, 2023 Exhibit 99.1 Sisecam Wyoming LLC(A Majority-Owned Subsidiary of Sisecam Resources LP) Financial Statements as of December 31, 2022 and 2021 and for the Years Ended December 31, 2022, 2021, and 2020, and Reports ofIndependent Registered Public Accounting Firms 1 SISECAM WYOMING LLC(A Majority Owned Subsidiary of Sisecam Resources LP) TABLE OF CONTENTS Page Number REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (PCAOB ID No. 243)3 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (PCAOB ID No. 34)5 BALANCE SHEETS AS OF DECEMBER 31, 2022 AND 20216 STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME FOR THE YEARS ENDED DECEMBER 31, 2022, 2021 AND 20207 STATEMENTS OF MEMBERS' EQUITY FOR THE YEARS ENDED DECEMBER 2022, 2021 AND 20208 STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2022, 2021 AND 20209 NOTES TO THE FINANCIAL STATEMENTS10 2 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Board of Managers and Members ofSisecam Wyoming LLCAtlanta, Georgia Opinion on the Financial Statements We have audited the accompanying balance sheet of Sisecam Wyoming LLC (the “Company”) as of December 31, 2022, the related statements of operations andcomprehensive income, members' equity, and cash flows for the year then ended, and the related notes (collectively referred to as the “financial statements”). In ouropinion, the financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2022, and the results of its operations andits cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statementsbased on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to beindependent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and ExchangeCommission and the PCAOB.We conducted our audit in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America.Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement,whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part ofour audit we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness ofthe Company’s internal control over financial reporting. Accordingly, we express no such opinion.Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performingprocedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financialstatements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overallpresentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion. Critical Audit Matter The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to becommunicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especiallychallenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the financial statements, taken as awhole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures towhich it relates. Agreements and Transactions with Affiliates As presented in the financial statements and further as described in Notes 1, 2, 12, and 13 to the financial statements, the Company’s accounts receivable – affiliates,due to affiliates, cost of products sold – affiliates, selling, general and administrative expenses – affiliates account balances were $53,924 thousand, $6,061 thousand,$15,136 thousand, and $19,261 thousand as of and for the year ended December 31, 2022. As the Company is a subsidiary and investee within two different globalgroup structures, agreements directly between the Company and other affiliates, or indirectly between affiliates the Company does not control, can have a significantimpact on recorded amounts or disclosures in the Company's financial statements, including any commitments and contingencies between the Company and affiliates or,potentially, third parties. We identified the completeness and accuracy of the Company's upstream affiliate relationships, transactions, and commitments and contingences originating outside ofSisecam USA and Ciner Enterprises, Inc. group and the impact of such matters on the financial statements as a critical audit matter. Auditing these elements involvedespecially challenging auditor judgement due to the nature and extent of audit effort and knowledge required to address these matters, including the extent of auditprocedures performed to search for completeness, then identify, assess, and test the accuracy of these transactions. 3 The primary procedures we performed to address this critical audit matter included: ●Testing the Company’s affiliate listing for the year ended December 31, 2022, including testing the completeness and accuracy of the Company’s affiliaterelationships, transactions, and commitments and contingencies originating outside of the Sisecam USA and Ciner Enterprises, Inc. group by (i) readingand evaluating publicly available financial filings and news sources related to the Company and its affiliates outside of the Sisecam USA and CinerEnterprises, Inc. group, (ii) inspecting director and executive officer questionnaires from certain of the Company’s directors and officers, (iii) searching thegeneral ledger for transactions with affiliates and for a selection of transactions, tracing to source documents, (iv) considering sources of information thatwere gathered during the audit that could indicate that affiliate relationships, transactions, and commitments and contingencies exist, (v) inquiring ofexecutive officers, key members of management, and certain members of the Board of Directors regarding affiliate relationships, transactions, andcommitments and contingencies, and (vi) confirming with the Company's ultimate parent companies that the affiliate relationships, transactions, andcommitments and contingencies identified and disclosed by the Company were complete and accurate. /s/ BDO USA, LLP We have served as the Company’s auditor since 2022. Atlanta, Georgia March 2, 2023 4 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Managers and Members ofSisecam Wyoming LLCAtlanta, Georgia Opinion on the Financial Statements We have audited the accompanying balance sheet of Sisecam Wyoming LLC (the "Company") as of December 31, 2021, the related statements of operations andcomprehensive income, members' equity, and cash flows for each of the two years in the period ended December 31, 2021, and the related notes (collectively referred toas the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31,2021, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2021, in conformity with accounting principlesgenerally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statementsbased on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to beindependent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and ExchangeCommission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States ofAmerica. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of materialmisstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financialreporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinionon the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performingprocedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financialstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overallpresentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. /s/ Deloitte & Touche LLP Atlanta, GeorgiaMarch 15, 2022 We began serving as the Company's auditor in 2008. In 2022 we became the predecessor auditor. 5 SISECAM WYOMING LLC(A Majority Owned Subsidiary of Sisecam Resources LP) BALANCE SHEETSAS OF DECEMBER 31, 2022 AND 2021(In thousands of dollars) 2022 2021 ASSETS CURRENT ASSETS: Cash and cash equivalents $21,165 $901 Accounts receivable, net 170,843 116,885 Accounts receivable-affiliates 53,924 49,517 Inventory 47,747 30,066 Other current assets 46,758 8,946 Total current assets 340,437 206,315 PROPERTY, PLANT, AND EQUIPMENT, NET 261,428 266,032 OTHER NON-CURRENT ASSETS 31,487 31,178 TOTAL ASSETS $633,352 $503,525 LIABILITIES AND MEMBERS' EQUITY CURRENT LIABILITIES: Current portion of long-term debt $8,805 $8,587 Accounts payable 37,066 21,918 Due to affiliates 6,061 2,128 Accrued expenses 59,326 40,548 Total current liabilities 111,258 73,181 LONG-TERM DEBT 128,177 114,982 OTHER NON-CURRENT LIABILITIES 16,113 9,767 Total liabilities 255,548 197,930 COMMITMENTS AND CONTINGENCIES (See Note 12) MEMBERS' EQUITY: Members’ equity — Sisecam Resources LP 173,497 152,809 Members’ equity — NRP Trona LLC 166,694 146,817 Accumulated other comprehensive income 37,613 5,969 Total members' equity 377,804 305,595 TOTAL LIABILITIES AND MEMBERS' EQUITY $633,352 $503,525 See notes to financial statements. 6 SISECAM WYOMING LLC(A Majority Owned Subsidiary of Sisecam Resources LP) STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOMEFOR THE YEARS ENDED DECEMBER 31, 2022, 2021 AND 2020(In thousands of dollars) 2022 2021 2020 SALES - AFFILIATES $ — $ — $177,891 SALES - OTHERS 720,120 540,139 214,340 Total net sales 720,120 540,139 392,231 COST OF PRODUCTS SOLD 542,409 456,121 337,393 COST OF PRODUCTS SOLD - AFFILIATES 15,136 3,468 — Total cost of products sold 557,545 459,589 337,393 GROSS PROFIT 162,575 80,550 54,838 SELLING, GENERAL AND ADMINISTRATIVE EXPENSES - AFFILIATES 19,261 16,635 17,398 SELLING, GENERAL AND ADMINISTRATIVE EXPENSES - OTHERS 5,377 3,731 946 OPERATING INCOME 137,937 60,184 36,494 OTHER INCOME (EXPENSE): Interest income — — 145 Interest expense (5,752) (5,042) (5,305)Other expense, net (120) (83) (304) Total other expense, net (5,872) (5,125) (5,464) NET INCOME 132,065 55,059 31,030 Other comprehensive income on derivative financial instruments 31,644 5,897 5,951 COMPREHENSIVE INCOME $163,709 $60,956 $36,981 See notes to financial statements. 7 SISECAM WYOMING LLC(A Majority Owned Subsidiary of Sisecam Resources LP) STATEMENTS OF MEMBERS' EQUITYFOR THE YEARS ENDED DECEMBER 31, 2022, 2021 AND 2020(In thousands of dollars) Accumulated Sisecam NRP Trona OtherComprehensive Total Members' Resources LP LLC Income (Loss) Equity Balance at January 1, 2020 $135,423 $130,113 $(5,879) $259,657 Allocation of net income 15,826 15,205 — 31,030 Capital distribution to members (14,790) (14,210) — (29,000)Other comprehensive income — — 5,951 5,951 Balance at December 31, 2020 $136,459 $131,108 $72 $267,639 Allocation of net income 28,080 26,979 — 55,059 Capital distribution to members (11,730) (11,270) — (23,000)Other comprehensive income — — 5,897 5,897 Balance at December 31, 2021 $152,809 $146,817 $5,969 $305,595 Allocation of net income 67,353 64,712 — 132,065 Capital distribution to members (46,665) (44,835) — (91,500)Other comprehensive income — — 31,644 31,644 Balance at December 31, 2022 $173,497 $166,694 $37,613 $377,804 See notes to financial statements. 8 SISECAM WYOMING LLC(A Majority Owned Subsidiary of Sisecam Resources LP) STATEMENTS OF CASH FLOWSFOR THE YEARS ENDED DECEMBER 31, 2022, 2021 AND 2020(In thousands of dollars) 2022 2021 2020 CASH FLOWS FROM OPERATING ACTIVITIES: Net income $132,065 $55,059 $31,030 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 27,598 31,468 28,494 Loss on disposal of assets, net 4,085 965 8 Other non-cash items 690 (487) 322 (Increase) decrease in: Accounts receivable - affiliates (4,407) (4,768) 8,418 Accounts receivable, net (53,958) (34,325) (4,650)Inventory (18,428) 303 (9,757)Other current and non-current assets (43) (2,069) (450)Increase (decrease) in: Accounts payable 15,203 5,000 2,155 Accrued expenses and other liabilities 19,920 5,715 2,489 Due to affiliates 3,933 (554) (382) Net cash provided by operating activities 126,658 56,307 57,677 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (28,264) (25,654) (42,218)Insurance proceeds — 809 — Net cash used in investing activities (28,264) (24,845) (42,218) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on revolving credit facility 158,000 83,500 211,500 Borrowings on other long-term debt — 29,000 30,000 Repayments on revolving credit facility (136,000) (116,000) (238,500)Repayments on other long-term debt (8,630) (3,031) (2,225)Debt issuance costs — (1,394) (554)Cash distribution to members (91,500) (23,000) (29,000) Net cash used in financing activities (78,130) (30,925) (28,779) NET INCREASE/(DECREASE) IN CASH AND CASH EQUIVALENTS 20,264 537 (13,320) CASH AND CASH EQUIVALENTS: Beginning of year 901 364 13,684 End of year $21,165 $901 $364 SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Interest paid during the year $5,113 $4,541 $5,115 SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING ACTIVITIES: Capital expenditures on account $2,772 $4,105 $1,977 See notes to financial statements. 9 SISECAM WYOMING LLC(A Majority Owned Subsidiary of Sisecam Resources LP) NOTES TO FINANCIAL STATEMENTSAS OF DECEMBER 31, 2022 AND 2021 AND FOR THE YEARS ENDED DECEMBER 31, 2022, 2021, AND 2020(Dollars in thousands) 1. Organizational Structure A 51% membership interest in Sisecam Wyoming LLC (the "Company," "we," "us," or "our," formerly known as Ciner Wyoming LLC) is owned by SisecamResources LP ("Sisecam LP" or the "Partnership," formerly known as Ciner Resources LP). NRP Trona LLC, a wholly owned subsidiary of Natural Resource PartnersL.P. ("NRP") owns a 49% membership interest in the Company. Sisecam LP is a master limited partnership traded on the New York Stock Exchange and is currentlyowned approximately 72% by Sisecam Chemicals Wyoming LLC ("SCW LLC," formerly known as Ciner Wyoming Holding Co.), approximately 2% by SisecamResource Partners LLC (the “general partner” or “Sisecam GP,” formerly known as Ciner Resource Partners LLC) and approximately 26% by the general public. SCWLLC is 100% owned by Sisecam Chemicals Resources LLC ("Sisecam Chemicals," formerly known as Ciner Resources Corporation) which is 60% owned by SisecamChemicals USA Inc. ("Sisecam USA") and 40% owned by Ciner Enterprises Inc. ("Ciner Enterprises"). Sisecam USA is a direct wholly-owned subsidiary of TürkiyeŞişe ve Cam Fabrikalari A.Ş, a Turkish Corporation ("Şişecam Parent"), which is an approximately 51%-owned subsidiary of Turkiye Is Bankasi Turkiye Is Bankasi("Isbank"). Şişecam Parent is a global company operating in soda ash, chromium chemicals, flat glass, auto glass, glassware glass packaging and glass fibersectors. Şişecam Parent was founded over 87 years ago, is based in Turkey and is one of the largest industrial publicly-listed companies on the Istanbul exchange. With production facilities in four continents and in 14 countries, Sisecam is one of the largest glass and chemicals producers in the world. Ciner Enterprises is adirect wholly-owned subsidiary of WE Soda Ltd., a U.K. Corporation (“WE Soda”). WE Soda is a direct wholly-owned subsidiary of KEW Soda Ltd., a U.K.corporation (“KEW Soda”), which is a direct wholly owned subsidiary of Akkan Enerji ve Madencilik Anonim Şirketi (“Akkan”). Akkan is directly and whollyowned by Turgay Ciner, the Chairman of the Ciner Group (“Ciner Group”), a Turkish conglomerate of companies engaged in energy and mining (including soda ashmining), media and shipping markets. On December 21, 2021, Ciner Enterprises (which was the indirect owner of approximately 74% of the common units in Sisecam LP and 100% of the general partner)completed the following transactions pursuant to the definitive agreement which Ciner Enterprises entered into with Sisecam USA, a direct subsidiary of ŞişecamParent on November 20, 2021 •Ciner Enterprises converted Ciner Resources Corporation into Sisecam Chemicals and Ciner Wyoming Holding Co., a direct wholly owned subsidiary ofSisecam Chemicals, into SCW LLC with SCW LLC in turn then directly owning approximately 74% of the common units in the Partnership and 100% of thegeneral partner (collectively, the "Reorganization Transactions"); •subsequent to the Reorganization Transactions, Ciner Enterprises sold to Sisecam USA, and Sisecam USA purchased, 60% of the outstanding units of SisecamChemicals owned by Ciner Enterprises for a purchase price of $300,000 (the “Sisecam Chemicals Sale”); and •at the closing of the Sisecam Chemicals Sale, Sisecam Chemicals, Ciner Enterprises, and Sisecam USA entered into a unitholders and operating agreement (the“Sisecam Chemicals Operating Agreement”) (collectively such transactions, the “CoC Transaction”). 10 Pursuant to the terms of the Sisecam Chemicals Operating Agreement, Sisecam USA and Ciner Enterprises have a right to designate six directors and four directors,respectively, to the board of directors of Sisecam Chemicals. In addition, the Sisecam Chemicals Operating Agreement provides that (i) the board of directors of thegeneral partner (the “MLP Board”) shall consist of six designees from Sisecam USA, two designees from Ciner Enterprises and three independent directors for aslong as the general partner is legally required to appoint such independent directors and (ii) the Partnership’s right to appoint four managers to the board ofmanagers of Sisecam Wyoming LLC (the “Wyoming Board”) shall be comprised of three designees from Sisecam USA and one designee from Ciner Enterprises. Each of Sisecam USA and Ciner Enterprises shall vote all units over which such unitholder has voting control in Sisecam Chemicals to elect to the board of directorsany individual designated by Sisecam USA and Ciner Enterprises. The Sisecam Chemicals Operating Agreement also requires the board of directors of SisecamChemicals to unanimously approve certain actions and commitments, including without limitation taking any action that would have an adverse effect on the masterlimited partnership status of the Partnership or any of its subsidiaries. As a result of Sisecam USA’s and Ciner Enterprise’s respective interests in SisecamChemicals and their respective rights under the Sisecam Chemicals Operating Agreement, each of Ciner Enterprises and Sisecam USA and their respective beneficialowners may be deemed to share beneficial ownership of the approximate 2% general partner interest in the Partnership and approximately 74% of the common unitsin the Partnership owned directly by SCW LLC and indirectly by Sisecam Chemicals as parent entity of SCW LLC. In 2022 the Partnership obtained the right to appoint an additional Sisecam USA designee to the Wyoming Board and the Ciner Enterprises designee on theWyoming Board was eliminated. 2. Nature of Operations and Summary of Significant Accounting Policies Nature of Operations The Company is in the business of mining trona ore to produce soda ash, and is a 51.0% majority-owned subsidiary of the Partnership. All of our soda ash processed is currently sold to various domestic and international customers. Sisecam Chemicals is the exclusive sales agent for the Company. Sisecam Chemicals has leveraged the distributor network established by Sisecam Parent and Ciner Group while independently reviewing current and potentialdistribution partners to optimize the Company’s reach into each market. A summary of the significant accounting policies is as follows: Basis of Presentation - The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the UnitedStates of America. Use of Estimates - The preparation of financial statements, in accordance with accounting principles generally accepted in the United States of America, requiresmanagement to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at thedates of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from thoseestimates. 11 Revenue Recognition - The Company’s revenues are recognized upon satisfaction of our performance obligations, that is, delivery and transfer of title to theproduct to our customers as discussed below. Additionally, the Company has made an accounting policy election to account for shipping and handling activitiesas fulfillment costs. We have one reportable segment, and our revenue is derived from the sale of soda ash which is our sole and primary good and service. Performance Obligations. A performance obligation is a promise in a contract to transfer a distinct good or service to the customer. A contract’s transactionprice is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. At contract inception,we assess the goods and services promised in contracts with customers and identify performance obligations for each promise to transfer to the customer, agood or service that is distinct. To identify the performance obligations, the Company considers all goods and services promised in the contract regardless ofwhether they are explicitly stated or are implied by customary business practices. From its analysis, the Company determined that the sale of soda ash iscurrently its only performance obligation. Many of our customer volume commitments are short-term and our performance obligations for the sale of soda ashare generally limited to single purchase orders. •When performance obligations are satisfied. Substantially all of our revenue is recognized at a point-in-time when control of goods transfers to thecustomer. •Transfer of Goods. The Company uses standard shipping terms across each customer contract with very few exceptions. Control transfer occurs atthe point at which the customer has the ability to direct the use of and obtain substantially all remaining benefits from the asset. The time at whichdelivery and transfer of title, and therefore control, occurs is the point when the product leaves our facilities for domestic customers, the point whenproduction reaches the port of loading or the point when the product is placed on a vessel for other international customers, thereby rendering ourperformance obligation fulfilled. Until the American National Soda Ash Corporation ("ANSAC") exit on December 31, 2020, the time at which deliveryand transfer of title occurred for ANSAC sales had been the same as domestic customers. •Payment Terms. Our payment terms vary by the type and location of our customers. The term between invoicing and when payment is due is notsignificant and consistent with typical terms in the industry. •Variable Consideration. We recognize revenue as the amount of consideration that we expect to receive in exchange for transferring promised goodsor services to customers. We do not adjust the transaction price for the effects of a significant financing component, as the time period betweencontrol transfer of goods and services and expected payment is one year or less. At the time of sale, we estimate provisions for different forms ofvariable consideration (discounts, rebates, and pricing adjustments) based on historical experience, current conditions and contractual obligations, asapplicable. The estimated transaction price is typically not subject to significant reversals. We adjust these estimates when the most likely amount ofconsideration we expect to receive changes, although these changes are typically immaterial. 12 •Returns, Refunds and Warranties. In the normal course of business, the Company does not accept returns, nor does it typically provide customerswith the right to a refund. •Freight. In accordance with FASB Accounting Standard Codification, Revenue from Contracts with Customers (Topic 606) (“ASC 606”), the Companymade a policy election to treat freight and related costs that occur after control of the related good transfers to the customer as fulfillment activitiesinstead of separate performance obligations. Therefore, freight is recognized as part of the cost of products sold at the point in which control of sodaash has transferred to the customer. Revenue Disaggregation. In accordance with ASC 606-10-50, the Company disaggregates revenue from contracts with customers into geographical regions.The Company determined that disaggregating revenue into these categories achieved the disclosure objectives to depict how the nature, timing, amount anduncertainty of revenue and cash flows are affected by economic factors. Refer to Note 14, “Segment Reporting,” for revenue disaggregated into geographicalregions. Revenue Contract Balances. The timing of revenue recognition, billings and cash collections results in billed receivables, unbilled receivables (contractassets), and customer advances and deposits (contract liabilities). •Contract Assets At the point of shipping, the Company has an unconditional right to payment generally that is only dependent on the passage oftime. In general, customers are billed and a receivable is recorded as goods are shipped. These billed receivables are reported as “AccountsReceivable, net” on the Balance Sheets as of December 31, 2022 and December 31, 2021. There were no contract assets as of December 31, 2022 andDecember 31, 2021. •Contract Liabilities There may be situations where customers are required to prepay for freight and insurance prior to shipment. The Companyaccounts for freight costs as fulfillment activities and therefore, such prepayments are considered a part of the single obligation to provide soda ash.In such instances, a contract liability for prepaid freight will be recorded. Freight Costs - The Company includes freight costs billed to customers for shipments administered by the Company in gross sales. The related freight costsincurred by the Company along with cost of products sold are deducted from gross sales to determine gross profit. Cash and Cash Equivalents - The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cashequivalents. Cash equivalents consist primarily of money market deposit accounts. Accounts Receivable - We determine expected credit losses for recorded receivables based on information about past events, including historical experience,current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. Inventory - Inventory is carried at the lower of cost and net realizable value. Cost is determined using the first-in, first-out method for raw material and finishedgoods inventory and the weighted average cost method for stores inventory. Costs include raw materials, direct labor and manufacturing overhead. Net realizablevalue is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. 13 •Raw material inventory includes material, chemicals and natural resources being used in the mining and refining process. •Finished goods inventory is the finished product soda ash. •Stores inventory includes parts, materials and operating supplies which are typically consumed in the production of soda ash and currently available for futureuse. If the inventory has been used within the preceding twelve months, it is classified as current assets and remainder is classified as non-current assets. Property, Plant, and Equipment - Property, plant, and equipment are stated at cost less accumulated depreciation. Depreciation is computed over the estimateduseful lives of depreciable assets, using the straight-line method. The estimated useful lives applied to depreciable assets are as follows: Useful LivesLand improvements10 yearsDepletable land15-60 yearsBuildings and building improvements10-30 yearsComputer hardware3-5 yearsMachinery and equipment5-20 years The Company's policy is to evaluate property, plant, and equipment for impairment whenever events or changes in circumstances indicate that its carrying amountmay not be recoverable. An indicator of potential impairment would include situations when the estimated future undiscounted cash flows are less than the carryingvalue. The amount of any impairment then recognized would be calculated as the difference between estimated fair value and the carrying value of the asset. Derivative Instruments and Hedging Activities - The Company may enter into derivative contracts from time to time to manage exposure to the risk of exchange ratechanges on its foreign currency transactions, the risk of changes in natural gas prices, and the risk of the variability in interest rates on borrowings. Gains andlosses on derivative contracts qualifying for hedge accounting are reported as a component of the underlying transactions. The Company follows hedgeaccounting for its hedging activities. All derivative instruments are recorded on the balance sheet at their fair values. The accounting for changes in the fair value ofa derivative depends on the intended use of the derivative and the resulting designation. The Company designates its derivatives based upon criteria establishedfor hedge accounting under generally accepted accounting principles. For a derivative designated as a fair value hedge, the gain or loss is recognized in earnings inthe period of change together with the offsetting gain or loss on the hedged item attributed to the risk being hedged. For a derivative designated as a cash flowhedge, the effective portion of the derivative’s gain or loss is initially reported as a component of accumulated other comprehensive income (loss) andsubsequently reclassified into earnings when the hedged exposure affects earnings. For derivatives not designated as hedges, the gain or loss is reported inearnings in the period of change. When the Company has natural gas physical forward contracts, they are accounted for under the normal purchases and normalsales scope exception. The Company has interest rate swap contracts, designated as cash flow hedges, to mitigate our exposure to possible increases in interest rates. The swap contractsconsist of two individual $12,500 swaps with an aggregate notional value of $25,000 at December 31, 2022 and three individual swaps with an aggregate notionalvalue of $37,500 at December 31, 2021. The swaps outstanding at December 31, 2022 have various maturities through 2024. 14 We enter into financial gas swap contracts, designated as cash flow hedges, to mitigate volatility in the price of natural gas related to a portion of the natural gas weconsume. These contracts generally have various maturities through 2024. These contracts had an aggregate notional value of $39,679 and $24,050 atDecember 31, 2022 and December 31, 2021, respectively. The following table presents the fair value of derivative assets and liabilities and the respective balance sheet locations as of: Assets Liabilities December 31, 2022 December 31, 2021 December 31, 2022 December 31, 2021 (in thousands)Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Derivatives designated as hedges: Interest rate swap contracts - currentOther current assets $204 Other current assets $ — Accrued Expenses $ — Accrued Expenses $188 Financial gas swap contracts - currentOther current assets 43,399 Other current assets 5,922 Accrued Expenses 7,921 Accrued Expenses 592 Interest rate swap contracts - non-currentOther non-current assets 782 Other non-current assets 131 Other non-currentliabilities — Other non-currentliabilities 222 Financial gas swap contracts - non-currentOther non-current assets 1,498 Other Non-current assets 2,443 Other non-currentliabilities 507 Other non-currentliabilities 1,438 Total derivatives designated as hedging instruments $45,883 $8,496 $8,428 $2,440 Income Tax - The Company is organized as a pass-through entity for federal income tax purposes and therefore are not subject to federal or certain state incometaxes. As a result, our members are responsible for income taxes based on their respective share of taxable income. Net income for financial statement purposes maydiffer significantly from taxable income reportable to members as a result of differences between the tax basis and financial reporting basis of assets and liabilitiesand the taxable income allocation requirements under the membership agreement. Reclamation Costs - The Company is obligated to return the land beneath its refinery and tailings ponds to its natural condition upon completion of operations andis required to return the land beneath its rail yard to its natural condition upon termination of the various lease agreements. The Company accounts for its land reclamation liability as an asset retirement obligation, which requires that obligations associated with the retirement of a tangiblelong-lived asset be recorded as a liability when those obligations are incurred, with the amount of the liability initially measured at fair value. Upon initiallyrecognizing a liability for an asset retirement obligation, an entity must capitalize the cost by recognizing an increase in the carrying amount of the related long-livedasset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the estimated useful life of the related asset.Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The estimated original liability calculated in 1996 for the refinery and tailing ponds was calculated based on the estimated useful life of the mine, which was 80 years,and on external and internal estimates as to the cost to restore the land in the future and state regulatory requirements. The liability was discounted using aweighted average credit-adjusted risk-free rate of approximately 6% and is being accreted throughout the estimated life of the related assets to equal the totalestimated costs with a corresponding charge being recorded to cost of products sold. 15 The Company has constructed a rail yard to facilitate loading and switching of rail cars. The Company is required to restore the land on which the rail yard isconstructed to its natural conditions. The original estimated liability for restoring the rail yard to its natural condition was calculated based on the land lease life of30 years and on external and internal estimates as to the cost to restore the land in the future. The liability is discounted using a credit-adjusted risk-free rate of 4.2%and is being accreted throughout the estimated life of the related assets to equal the total estimated costs with a corresponding charge being recorded to cost ofproducts sold. Fair Value of Financial Instruments - The following methods and assumptions were used to estimate the fair values of each class of financial instruments: The Company measures certain financial and non-financial assets and liabilities at fair value on a recurring basis. Fair value is defined as the price that would bereceived to sell an asset or paid to transfer a liability in the principal or most advantageous market in an orderly transaction between market participants on themeasurement date. Fair value disclosures are reflected in a three-level hierarchy, maximizing the use of observable inputs and minimizing the use of unobservableinputs. Financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, derivative financial instruments andlong-term debt. The carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and accrued expenses approximate their fair valuebecause of the nature of such instruments. Our long-term debt and derivative financial instruments are measured at their fair values with Level 2 inputs based onquoted market values for similar but not identical financial instruments. The carrying value of the Sisecam Wyoming Credit Facility (as defined below) materially reflects the fair value as the rate is variable and its key terms are similar toindebtedness with similar amounts, durations and credit risks. The fair value of the Sisecam Wyoming Equipment Financing Arrangement was $41,739 versus acarrying value of $44,982 at December 31, 2022. See Note 8, “Debt,” for additional information on our debt arrangements. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Fair valueaccounting requires that these financial assets and liabilities be classified into one of the following three categories: •Level 1-inputs to the valuation methodology are quoted prices (unadjusted) for an identical asset or liability in an active market. •Level 2-inputs to the valuation methodology include quoted prices for a similar asset or liability in an active market or model-derived valuations in which allsignificant inputs are observable for substantially the full term of the asset or liability. •Level 3-inputs to the valuation methodology are unobservable and significant to the fair value measurement of the asset or liability. Subsequent Events - The Company has evaluated all subsequent events through March 2, 2023, the date the financial statements were available to be issued. SeeNote 15, "Subsequent Events," for additional information. 16 Recently Issued and Adopted Accounting Standards - In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effectsof Reference Rate Reform on Financial Reporting (“ASU 2020-04”) providing temporary guidance to ease the potential burden in accounting for reference ratereform primarily resulting from the discontinuation of the London Inter-bank Offered Rate (“LIBOR”), which occurred on December 31, 2021 except U.S. DollarLIBOR, which is expected to occur on June 30, 2023. The amendments in ASU 2020-04 are elective and apply to all entities that have contracts, hedgingrelationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued. The new guidance provides the following optionalexpedients: (i) simplifies accounting analyses under current GAAP for contract modifications; (ii) simplifies the assessment of hedge effectiveness and allowshedging relationships affected by reference rate reform to continue; and (iii) allows a one-time election to sell or transfer debt securities classified as held to maturitythat reference a rate affected by reference rate reform. An entity may elect to apply the amendments prospectively from March 12, 2020 through December 31, 2022by accounting topic. The Company evaluated ASU 2020-04 and concluded that there was no impact to the Company’s financial statements. In January 2021, the FASB issued ASU 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”) to clarify that all derivative instruments affected bychanges to the interest rates used for discounting, margining or contract price alignment (commonly referred to as the discounting transition) are in the scope ofASC 848. The amendments also clarify other aspects of the guidance in ASC 848 and addresses the effects of the cash compensation adjustment provided in thediscounting transition on certain aspects of hedge accounting. The guidance in ASC 848 also allows entities to make a one-time election to sell and/or transfer toavailable for sale or trading any held-to-maturity debt securities that refer to an interest rate affected by reference rate reform and were classified as held to maturitybefore January 1, 2020. The original guidance and the recently issued ASU are effective as of their issuance dates. The relief provided is temporary and generallycannot be applied to contract modifications that occur after December 31, 2022 or hedging relationships entered into or evaluated after that date. However, theFASB has indicated that it will revisit the sunset date in ASC 848 after the LIBOR administrator makes a final decision on a phaseout date. The LIBOR administratorrecently extended the publication of the overnight and the one-, three-, six- and 12-month U.S. Dollar LIBOR settings through June 30, 2023, when many existingcontracts that reference LIBOR will have expired. The Company evaluated ASU 2021-01 and concluded that there was no impact to the Company’s financialstatements. In December 30, 2022, the FASB issued a new effective date for Reference Rate Reform (Topic 848) and Derivatives and Hedging (Topic 815) - Deferral of the SunsetDate (ASU 2020-06), to December 31, 2024. 3. ACCOUNTS RECEIVABLE, NET Accounts receivable, net consisted of the following at December 31: 2022 2021 Trade receivables, net $162,957 $109,677 Other receivables 7,886 7,208 Total $170,843 $116,885 4. INVENTORY Inventory consisted of the following at December 31: 2022 2021 Raw materials $14,776 $10,521 Finished goods 23,670 9,247 Stores inventory, current 9,301 10,298 Total $47,747 $30,066 17 5. PROPERTY, PLANT, AND EQUIPMENT, NET Property, plant, and equipment, net consisted of the following at December 31: 2022 2021 Land and land improvements $192 $192 Depletable land 4,031 2,957 Buildings and building improvements 168,209 164,254 Computer hardware 6,592 5,589 Machinery and equipment 732,262 686,630 Total 911,286 859,622 Less accumulated depreciation, depletion and amortization (679,966) (653,258)Total net book value 231,320 206,364 Construction in progress 30,108 59,668 Property, plant, and equipment, net $261,428 $266,032 Depreciation, depletion and amortization expense on property, plant, and equipment was $26,414, $30,049, and $27,399 for the years ended December 31, 2022,December 31, 2021 and December 31, 2020, respectively. 6. OTHER NON-CURRENT ASSETS Other non-current assets consisted of the following at December 31: 2022 2021 Stores inventory, non-current $22,353 $20,524 Internal-use software, net of accumulated amortization 4,868 5,691 Other 4,266 4,963 Total $31,487 $31,178 During the years ended December 31, 2022, 2021 and 2020, in accordance with ASC 350-40, Internal Use Software, we capitalized $38, $869, and $488, respectively, ofcertain internal use software development costs. Software development activities generally consist of three stages (i) the research and planning stage, (ii) theapplication and infrastructure development stage, and (iii) the post-implementation stage. Costs incurred in the planning and post-implementation stages ofsoftware development, or other maintenance and development expenses that do not meet the qualification for capitalization are expensed as incurred. Costs incurredin the application and infrastructure development stage, including significant enhancements and upgrades, are capitalized. These software development costs areamortized on a straight-line basis over the estimated useful life of five to ten years under depreciation and amortization expense which is included in the cost ofproducts sold financial statement line item of the statements of operations. During the years ended December 31, 2022, 2021 and 2020, we amortized internal usesoftware development costs of $862, $853, and $725, respectively. Amortization for these internal use software development costs is expected to be approximately$800 per year. 18 7. ACCRUED EXPENSES Accrued expenses consisted of the following at December 31: 2022 2021 Accrued capital expenditures $1,596 $2,873 Accrued employee compensation & benefits 11,302 8,991 Accrued energy costs 11,726 7,009 Accrued royalty costs 11,096 7,571 Accrued other taxes 5,361 4,236 Accrued derivatives 7.921 781 Received not invoiced accruals 8,812 7,955 Other accruals 1,512 1,132 Total $59,326 $40,548 8. DEBT Long-term debt consisted of the following at December 31: 2022 2021 Sisecam Wyoming Equipment Financing Arrangement Security Note Number 001 with maturity date of March 26, 2028,fixed interest rate of 2.479% $21,505 $24,569 Sisecam Wyoming Equipment Financing Arrangement Security Note Number 002 with maturity date of December 17,2026, fixed interest rate of 2.4207% 23,477 29,000 Sisecam Wyoming Credit Facility, secured principal expiring on October 28, 2026, variable interest rate as a weightedaverage rate of 5.72% at December 31, 2022 92,000 70,000 Total debt 136,982 123,569 Less current portion of long-term debt 8,805 8,587 Total long-term debt $128,177 $114,982 Aggregate maturities required on long-term debt at December 31, 2022 are due in future years as follows: 2023 $8,843 2024 9,062 2025 9,285 2026 101,515 2027 and thereafter 8,410 Total $137,115 Sisecam Wyoming Equipment Financing Arrangement Master Loan and Security Agreement: On March 26, 2020, Sisecam Wyoming LLC and Banc of America Leasing & Capital, LLC, as lender (the “Equipment Financing Lender”), entered into an equipmentfinancing arrangement (“Sisecam Wyoming Equipment Financing Arrangement”), including a Master Loan and Security Agreement, dated as of March 25, 2020 (asamended, the “Master Agreement”) and an Equipment Security Note Number 001, dated as of March 25, 2020 (the “Sisecam Wyoming Equipment FinancingArrangement Security Note Number 001,” or the “Initial Secured Note”), which provides the terms and conditions for the debt financing of certain equipment relatedto Sisecam Wyoming’s natural gas-fired turbine co-generation facility that became operational in March 2020. Each equipment financing entered into under theSisecam Wyoming Equipment Financing Arrangement will be evidenced by the execution of one or more equipment notes (including the Initial Secured Note) thatincorporate the terms and conditions of the Master Agreement (each, an “Equipment Note”). In order to secure the payment and performance of SisecamWyoming’s obligations under the Sisecam Wyoming Equipment Financing Arrangement, Sisecam Wyoming granted to the Equipment Financing Lender acontinuing security interest in all of Sisecam Wyoming’s right, title and interest in and to the Equipment (as defined in the Master Agreement) and certain relatedcollateral. 19 On October 28, 2021, in connection with the entry into the Sisecam Wyoming Credit Facility (which replaced the Prior Sisecam Wyoming Credit Facility), SisecamWyoming and the Equipment Financing Lender entered into an amendment to the Master Agreement, in order to amend and restate all covenants that are basedupon a specified level or ratio relating to assets, liabilities, indebtedness, rentals, net worth, cash flow, earnings, profitability, or any other accounting-basedmeasurement or test to conform with the Sisecam Wyoming Credit Facility. On December 17, 2021, Sisecam Wyoming and the Equipment Financing Lender entered into Amendment Number 001 to the Initial Secured Note (“First Amendmentto the Initial Secured Note”). The First Amendment to the Initial Secured Note, provides among other things: (i) upon the occurrence of an early full payoff of theSecond Secured Note (as defined below), Sisecam Wyoming shall simultaneously pay, in full, the outstanding amount of the Initial Secured Note and (ii) SisecamWyoming grants to Equipment Financing Lender a security interest in all collateral securing the Second Secured Note to secure Sisecam Wyoming’s obligationsunder the Initial Secured Note. At December 31, 2022, Sisecam Wyoming was in compliance with all financial covenants of the Sisecam Wyoming Equipment Financing Arrangement. The Sisecam Wyoming Equipment Financing Arrangement: (1) incorporates all covenants in the Sisecam Wyoming Credit Facility (as defined below), now or hereinafter existing, or in any applicable replacement credit facilityaccepted in writing by the Equipment Financing Lender, that are based upon a specified level or ratio relating to assets, liabilities, indebtedness, rentals, net worth,cash flow, earnings, profitability, or any other accounting-based measurement or test, and (2) includes customary events of default subject to applicable graceperiods, including, among others, (i) payment defaults, (ii) certain mergers or changes in control of Sisecam Wyoming, (iii) cross defaults with certain otherindebtedness (a) to which the Equipment Financing Lender is a party or (b) to third parties in excess of $10,000, and (iv) the commencement of certain insolvencyproceedings or related events identified in the Master Agreement. Upon the occurrence of an event of default, in its discretion, the Equipment Financing Lendermay exercise certain remedies, including, among others, the ability to accelerate the maturity of any Equipment Note such that all amounts thereunder will becomeimmediately due and payable, to take possession of the Equipment identified in any Equipment Note, and to charge Sisecam Wyoming a default rate of interest onall then outstanding or thereafter incurred obligations under the Sisecam Wyoming Equipment Financing Arrangement: Among other things, Security Note Number 001: •was executed on March 25, 2020; •has a principal amount of $30,000; •has a maturity date of March 26, 2028; •shall be payable by Sisecam Wyoming to the Equipment Financing Lender in 96 consecutive monthly installments of principal and interest commencing onApril 26, 2020 and continuing thereafter until the maturity date of the Initial Secured Note, which shall be in the amount of approximately $307 for the first95 monthly installments and approximately $4,307 for the final monthly installment; and •entitles Sisecam Wyoming to prepay all (but not less than all) of the outstanding principal balance of the Initial Secured Note (together with all accruedinterest and other charges and amounts owed thereunder) at any time after one (1) year from the date of the Initial Secured Note, subject to SisecamWyoming paying to the Equipment Financing Lender an additional prepayment amount determined by the amount of principal balance prepaid and thedate such prepayment is made. 20 In connection with the Second Sisecam Wyoming Amendment (as defined below), the Master Agreement was amended to incorporate, among other things, themodified covenants set forth in the Second Sisecam Wyoming Amendment related to consolidated leverage ratios of Sisecam Wyoming. In December 2021 a waiver was obtained to accommodate the CoC Transaction. First Amendment to Security Note Number 001: On December 17, 2021, Sisecam Wyoming and the Equipment Financing Lender entered into Amendment Number 001 to the Initial Secured Note (“First Amendmentto the Initial Secured Note”). The First Amendment to the Initial Secured Note, provides among other things: (i) upon the occurrence of an early full payoff of theSecond Secured Note, Sisecam Wyoming shall simultaneously pay, in full the outstanding amount of the Initial Secured Note and (ii) Sisecam Wyoming grants toEquipment Financing Lender a security interest in all collateral securing the Second Secured Note to secure Sisecam Wyoming’s obligations under the InitialSecured Note. Sisecam Wyoming’s balance under the Sisecam Wyoming Equipment Financing Arrangement at December 31, 2022 was $21,638 ($21,505 net of financing costs). Among other things, Security Note Number 002: •was executed on December 17, 2021; •has a principal amount of $29,000; •has a maturity date of December 17, 2026; •shall be payable by Sisecam Wyoming to the Equipment Financing Lender in 60 consecutive monthly installments of principal and interest commencing onJanuary 17, 2022 and continuing thereafter until the maturity date of the Second Secured Note, which shall be in the amount of approximately $514 for eachmonthly installment; •entitles Sisecam Wyoming to prepay all (but not less than all) of the outstanding principal balance of the Second Secured Note (together with all accruedinterest and other charges and amounts owed thereunder) at any time after one (1) year from the date of the Second Secured Note, subject to SisecamWyoming paying to the Equipment Financing Lender an additional prepayment amount determined by the amount of principal balance prepaid and thedate such prepayment is made and subject to Sisecam Wyoming simultaneously paying, in full, the outstanding amount of the Initial Secured Note asdiscussed above; and •upon the occurrence of full payoff of Initial Secured Note dated as of March 25, 2020 under the Master Agreement, Sisecam Wyoming shall simultaneouslypay, in full, the outstanding amount of this Second Secured Note. Sisecam Wyoming Credit Facility On October 28, 2021, Sisecam Wyoming entered into a new $225,000 senior secured revolving credit facility (the “Sisecam Wyoming Credit Facility”) with each ofthe lenders listed on the respective signature pages thereof and Bank of America, N.A., as administrative agent, swing line lender and letter of credit issuer. TheSisecam Wyoming Credit Facility matures on October 28, 2026. On closing, the amount drawn under this new Sisecam Wyoming Credit Facility approximated theamount outstanding under the Prior Sisecam Wyoming Credit Facility at September 30, 2021. 21 The Sisecam Wyoming Credit Facility provides, among other things: •a sublimit up to $40,000 for the issuance of standby letters of credit and a sublimit up to $20,000 for swingline loans; •an accordion feature that enables Sisecam Wyoming to increase the revolving borrowings under the Sisecam Wyoming Credit Facility by up to anadditional $250,000 (subject to certain conditions); •in addition to the aforementioned revolving borrowings, an ability to incur up to $225,000 of additional term loan facility indebtedness to finance SisecamWyoming’s capacity expansion capital expenditures; (subject to certain conditions); •a pledge by Sisecam Wyoming of substantially all of Sisecam Wyoming’s assets (subject to certain exceptions), including: (i) all present and future sharesof any subsidiaries of Sisecam Wyoming (whether now existing or hereafter created) and (ii) all personal property of Sisecam Wyoming (subject to certainconditions); •contains various covenants and restrictive provisions that limit (subject to certain exceptions) Sisecam Wyoming’s ability to: (i) incur certain liens or permitthem to exist; (ii) incur or guarantee additional indebtedness; (iii) make certain investments and acquisitions related to Sisecam Wyoming’s operations inWyoming); (iv) merge or consolidate with another company; (v) transfer, sell or otherwise dispose of assets, (vi) make distributions; (vii) change the natureof Sisecam Wyoming’s business; and (viii) enter into certain transactions with affiliates; •a requirement to maintain a quarterly consolidated leverage ratio of not more than 3.25:1:00; provided, however, subject to certain conditions, SisecamWyoming shall have the ability to increase the maximum consolidated leverage ratio to 3.75:1.00 for a year while Sisecam Wyoming is undertaking capacityexpansion capital expenditures; •a requirement to maintain a quarterly consolidated interest coverage ratio of not less than 3.00:1.00; and •customary events of default including (i) failure to make payments required under the Sisecam Wyoming Credit Facility, (ii) events of default resulting fromfailure to comply with covenants and financial ratios, (iii) the occurrence of a voluntary change of control, as a result of which Sisecam Wyoming is directlyor indirectly controlled by persons or entities not currently directly or indirectly controlling Sisecam Wyoming, (iv) the institution of insolvency or similarproceedings against Sisecam Wyoming, and (v) the occurrence of a cross default under any other material indebtedness Sisecam Wyoming may have.Upon the occurrence of an event of default, in their discretion, the Sisecam Wyoming Credit Facility lenders may exercise certain remedies, including,among others, accelerating the maturity of any outstanding loans, accrued and unpaid interest and all other amounts owing and payable such that allamounts thereunder will become immediately due and payable, and if not timely paid upon such acceleration, to charge Sisecam Wyoming a default rate ofinterest on all amounts outstanding under the Sisecam Wyoming Credit Facility. However, upon the occurrence of an involuntary change of control ofSisecam Wyoming, and after the passage of time as specified in the Sisecam Wyoming Credit Facility, Sisecam Wyoming’s debt thereunder would beaccelerated. In addition, loans under the Sisecam Wyoming Credit Facility (other than any swingline loans) will bear interest at Sisecam Wyoming’s option at either: •a base rate, which equals the highest of (i) Bank of America’s prime rate, (ii) the federal funds rate then in effect on such day, plus 0.50%; (iii) one-monthBloomberg Short-Term Bank Yield Index (“BSBY”) adjusted daily rate, plus 1.0%; and (iv) 1.0%, plus, in each case, an applicable margin range from 0.50%to 1.75% based on the consolidated leverage ratio of Sisecam Wyoming; or •a BSBY rate for interest periods of one, three or six months, plus, in each case, an applicable margin range from 1.50% to 2.75% based on the consolidatedleverage ratio of Sisecam Wyoming. 22 In addition, if a BSBY rate ceases to exist for any period, loans under the Sisecam Wyoming Credit Facility will bear interest based on alternative indexes (includingthe secured overnight financing rate), plus an applicable margin. The unused portion of the Sisecam Wyoming Credit Facility is subject to a per annum commitment fee and the applicable margin of the interest rate under theSisecam Wyoming Credit Facility will be determined as follows: Pricing Tier Leverage Ratio BSBY Rate Loans Base Rate Loans Commitment Fee 1 < 1.25:1.0 1.50% 0.50% 0.23% 2 ≥ 1.25:1.0 but < 1.75:1.0 1.75% 0.75% 0.25% 3 ≥ 1.75:1.0 but < 2.25:1.0 2.00% 1.00% 0.28% 4 ≥ 2.25:1.0 but < 3.00:1.0 2.25% 1.25% 0.30% 5 ≥ 3.00:1.0 but < 3.50:1.0 2.50% 1.50% 0.33% 6 ≥ 3.50:1.0 2.75% 1.75% 0.35% The Sisecam Wyoming Credit Facility permits the consolidated leverage ratio as of the end of each fiscal quarter of Sisecam Wyoming, commencing with the fiscalquarter ending December 31, 2021, to be greater than 3.25: 1.00; provided, however, during the Specified Capital Expansion Holiday, the lenders shall not permit theconsolidated leverage ratio as of the end of each fiscal quarter of Sisecam Wyoming to be greater than 3.75:1.00. “Specified Capital Expansion Holiday” means theperiod consisting of four (4) full fiscal quarters after the Sisecam Wyoming has (i) made capital expenditures related to the Specified Capital Expansion (or othercapital expansion project approved by the board of directors, board of managers or equivalent governing body of Sisecam Wyoming) of at least $200,000 and (ii)provided written notice to the administration that Sisecam Wyoming is electing to initiate such Specified Capital Expansion Holiday. “Specified Capital Expansion”means expansion activities related to the lenders’ soda ash operations in Wyoming which have been approved in writing by the Sisecam Wyoming’s board ofdirectors, board of managers or equivalent governing body. The Sisecam Wyoming Credit Facility permits the consolidated interest coverage ratio as of the end ofany fiscal quarter of Sisecam Wyoming, commencing with the fiscal quarter ending December 31, 2021, to be less than 3.00:1.00. In connection with the CoC Transaction (as defined in Note 1 above), on December 17, 2021, Sisecam Wyoming entered into the First Amendment (“FirstAmendment”) to its $225,000 senior secured revolving credit facility, dated as of October 28, 2021 (as amended, the “Sisecam Wyoming Credit Facility”), with eachof the lenders listed on the respective signature pages thereof and Bank of America, N.A., as administrative agent, swing line lender and letter of credit issuer.Pursuant to the First Amendment, the definition of “Change of Control” under the Credit Facility was revised to reflect that the updated indirect ownership ofSisecam Resources LP and Sisecam GP as contemplated by the CoC Transaction will not cause a Change of Control under the Sisecam Wyoming Credit Facility solong as the CoC Transaction occurred prior to March 31, 2022. The CoC Transaction did not cause a change in control event under the Credit Facility. Management is not aware of any current circumstances that would result in an event of default under the Sisecam Wyoming Credit Facility at December 31, 2022 orin the next twelve months. WE Soda and Ciner Enterprises Facilities Agreement On August 1, 2018, Ciner Enterprises, the entity that, prior to the CoC Transaction, indirectly owned and controlled Sisecam Wyoming, refinanced its existing creditagreement and entered into a new facilities agreement, to which WE Soda and Ciner Enterprises (as borrowers), and KEW Soda, WE Soda, WE Soda KimyaYatırımları Anonim Şirketi, Ciner Kimya Yatırımları Sanayi ve Ticaret Anonim Şirketi, Ciner Enterprises, SCW LLC, and Sisecam Chemicals (as original guarantors andtogether with the borrowers, the “Ciner Obligors”), were parties (as amended and restated or otherwise modified, the “Facilities Agreement”), and certain relatedfinance documents. On February 20, 2022, the Facilities Agreement was refinanced and Ciner Enterprises, SCW LLC, and Sisecam Chemicals were released from being Ciner Obligors ofthe Facilities Agreement and are not a party to the WE Soda refinanced agreement. 23 9. OTHER NON-CURRENT LIABILITIES Other non-current liabilities consisted of the following at December 31: 2022 2021 Reclamation reserve $8,434 $7,993 Derivative instruments and hedges, fair value and other liabilities 595 1,660 Accrued non-income tax related taxes 7,084 114 Total $16,113 $9,767 Details of the reclamation reserve shown above are as follows: 2022 2021 Reclamation reserve at beginning of year $7,993 $7,337 Accretion expense 441 409 Reclamation adjustment (1) — 247 Reclamation reserve at end of year $8,434 $7,993 (1) The reclamation costs are periodically evaluated for adjustments by the Wyoming Department of Environmental Quality. See Note 12 “Commitments andContingencies,” “Mine Permit Bonding Commitment” for additional information on our reclamation reserve at December 31, 2022 and 2021. 10. EMPLOYEE BENEFIT PLANS The Company participates in various benefit plans offered and administered by Sisecam Chemicals and is allocated its portions of the annual costs related thereto.The specific plans are as follows: Retirement Plans - Benefits provided under the retirement plans for salaried employees and hourly employees (the “Retirement Plans”) are based upon years ofservice and average compensation for the highest 60 consecutive months of the employee’s last 120 months of service, as defined. The Retirement Plans coversubstantially all full-time employees hired before May 1, 2001. Sisecam Chemicals’ Retirement Plans had a net liability balance of $26,576 and $32,843 at December 31,2022 and December 31, 2021, respectively. Sisecam Chemicals’ current funding policy is to contribute an amount within the range of the minimum required and themaximum tax-deductible contribution. The Company’s allocated portion of the Retirement Plans' net periodic pension (benefit) cost for the years ended December31, 2022, 2021 and 2020 was $(3,705), $(2,723), and $(1,260), respectively. The variation in annual pension (benefit) cost was driven by a better-than-expected returnon assets and lower interest expense assumptions. Savings Plan -The 401(k) retirement plan (the “401(k) Plan”) covers all eligible hourly and salaried employees. Eligibility is limited to all domestic residents and anyforeign expatriates who are in the United States indefinitely. The 401(k) Plan permits employees to contribute specified percentages of their compensation, while theCompany makes contributions based upon specified percentages of employee contributions. Participants hired on or subsequent to May 1, 2001, will receive anadditional contribution from the Company based on a percentage of the participant’s base pay. Contributions made to the 401(k) Plan for the years ended December31, 2022, 2021, and 2020 were $3,604, $3,356, and $3,366, respectively. Postretirement Benefits - Most of the Company’s employees hired before January 2, 2017 are eligible for postretirement benefits other than pensions if they reachage 58 while still employed with at least 10 years of service. 24 The postretirement benefits are accounted for by Sisecam Chemicals on an accrual basis over an employee’s period of service. The postretirement plan, excludingpensions, is not funded, and Sisecam Chemicals has the right to modify or terminate the plan. The post-retirement plan had a net unfunded liability of $7,652 and$10,695 on December 31, 2022 and December 31, 2021, respectively. The Company's allocated portion of postretirement cost (benefit) for the years ended December 31, 2022, 2021 and 2020, was $713, $871, and $1,233, respectively. 11. ACCUMULATED OTHER COMPREHENSIVE (LOSS)/INCOME Accumulated other comprehensive (loss)/income as of December 31, 2022, 2021 and 2020 consisted of the following: Interest Rate SwapContracts Financial Gas SwapContracts Total BALANCE at January 1, 2020 $(855) $(5,024) $(5,879)Other comprehensive (loss)/income before reclassification (1,253) 3,762 2,509 Amounts reclassified from accumulated other comprehensive income 835 2,607 3,442 Net current-period other comprehensive (loss)/income (418) 6,369 5,951 BALANCE at December 31, 2020 $(1,273) $1,345 $72 Other comprehensive income before reclassification 205 5,692 5,897 Amounts reclassified from accumulated other comprehensive income/(loss) 702 (702) — Net current-period other comprehensive income 907 4,990 5,897 BALANCE at December 31, 2021 $(366) $6,335 $5,969 Other comprehensive income before reclassification 1,249 44,215 45,464 Amounts reclassified from accumulated other comprehensive income/(loss) 262 (14,082) (13,820)Net current-period other comprehensive income 1,511 30,133 31,644 BALANCE at December 31, 2022 $1,145 $36,468 $37,613 The components of other comprehensive income/(loss), that have been reclassified out of Accumulated other comprehensive income/loss consisted of thefollowing: 2022 2021 2020 Affected Line Items on the Statements ofOperations and Comprehensive IncomeDetails about other comprehensive income/(loss) components: Gains/(losses) on cash flow hedges: Interest rate swap contracts $262 $702 $835 Interest expenseFinancial gas swap contracts (14,082) (702) 2,607 Cost of products soldTotal reclassifications for the period $(13,820) $— $3,442 12. COMMITMENTS AND CONTINGENCIES Lease and License Commitments The Company leases and licenses mineral rights from the U.S. Bureau of Land Management, the state of Wyoming, Sweetwater Royalties, LLC a subsidiary ofSweetwater Trona OpCo LLC and the successor in interest to the license to the Rock Springs Royalty Company, LLC (“RSRC”), an affiliate of Occidental PetroleumCorporation (formerly an affiliate of Anadarko Petroleum Corporation), and other private parties which provide for royalties based upon production volume. TheCompany has a perpetual right of first refusal with respect to these leases and license and intends to continue renewing the leases and license as has been itspractice. 25 Sisecam Chemicals enters into contracts with one railroad company for the majority of the domestic rail freight services that the Company receives and the relatedfreight and logistics costs are allocated to the Company. For the years ended December 31, 2022 and 2021, the Company shipped over 90% of our soda ash to ourcustomers initially via a single rail line owned and controlled by the railroad company. If Sisecam Chemicals does not ship at least a significant portion of our sodaash production on the railroad company’s rail line during a twelve-month period, it must pay the railroad company a shortfall payment under the terms of ourtransportation agreement. The Company assists the majority of its domestic customers in arranging their freight services. During the years ended December 31,2022 and 2021, Sisecam Chemicals had no shortfall payments and does not expect to make any such payments in the future. Sisecam Chemicals renewed itsagreement with the railroad company in October 2021, which expires on December 31, 2025. The Company entered into a 10-year rail yard switching and maintenance agreement on December 1, 2011. Under the agreement, the rail-switching services areprovided at the Company’s rail yard. The Company’s rail yard is constructed on land leased by the third party from Rock Springs Grazing Association and on landthat the third party holds an easement from Sweetwater Surface LLC. The land lease is renewable every five years for a total period of thirty years, while theSweetwater Surface LLC easement is perpetual. The Company has agreed with the third party for the assignment of the lease and easement to the Company at anytime during the land lease term. An immaterial annual rental is paid under the easement and lease. On December 1, 2021, the Company entered into a new 10-yearagreement for rail yard switching and maintenance services. As of December 31, 2022, the total minimum contractual rental commitments under the Company’s various operating leases, including renewal periods isapproximately $1,625 with the amount due in any of the next five years being immaterial. Sisecam Chemicals typically enters into operating lease contracts with various lessors for rail cars to transport product to customer locations and warehouses. Railcar leases under these contractual commitments range for periods from one to ten years. Sisecam Chemicals’ obligation related to these rail car leases are $9,424 in 2023, $7,862 in 2024, $6,501 in 2025, $5,195 in 2026 and $2,873 thereafter. Total lease expense allocated to the Company from Sisecam Chemicals was approximately$10,996, $10,583, and $11,304 for the years ended December 31, 2022, 2021 and 2020, respectively and is recorded in cost of products sold. Purchase Commitments - We have financial gas swap contracts to mitigate volatility in the price of natural gas. As of December 31, 2022, these contracts' aggregatenotional value totaled approximately $39,679 for the purchase of a portion of our natural gas requirements over approximately the next two years. The supplypurchase agreements have specific commitments of $34,057 in 2023, and $5,652 in 2024. The Company has a separate contract through 2031 for the transportation ofnatural gas with an average minimum annual cost of approximately $1,500 per year. Legal and Environmental Matters- From time to time we are party to various claims and legal proceedings related to our business. Although the outcome of theseproceedings cannot be predicted with certainty, management does not currently expect any such legal proceedings we may be involved in from time to time to havea material effect on our business, financial condition and results of operations. We cannot predict the nature of any future claims or proceedings, nor the ultimatesize or outcome of any such claims and legal proceedings and whether any damages resulting from them will be covered by insurance. Mine Permit Bonding Commitment - Our operations are subject to oversight by the Land Quality Division of Wyoming Department of Environmental Quality(“WDEQ”). Our principal mine permit issued by the Land Quality Division, requires the Company to provide financial assurances for our reclamation obligations forthe estimated future cost to reclaim the area of our processing facility, surface pond complex and on-site sanitary landfill. The Company provides such assurancesthrough a third-party surety bond (the “Surety Bond”). The Surety Bond amount was $41,800 on December 31, 2022 and 2021. 26 13. AGREEMENTS AND TRANSACTIONS WITH AFFILIATES Agreements and transactions with affiliates have a significant impact on the Company’s financial statements because the Company is a subsidiary and investeewithin two different global group structures. Agreements directly between the Company and other affiliates, or indirectly between affiliates that the Company doesnot control, can have a significant impact on recorded amounts or disclosures in the Company's financial statements, including any commitments and contingenciesbetween the Company and affiliates, or potentially, third parties. Sisecam Chemicals was the exclusive sales agent for the Company and through its membership in ANSAC, through December 31, 2020, Sisecam Chemicals hadresponsibility for promoting and increasing the use and sale of soda ash and other refined or processed sodium products produced. Through December 31, 2020,ANSAC served as the primary international distribution channel for the Company and two other U.S. manufacturers of trona-based soda ash. ANSAC operated ona cooperative service-at-cost basis to its members such that typically any annual profit or loss is passed through to the members. As previously disclosed as partof its strategic initiative to gain better direct access and control of international customers and logistics and the ability to leverage the expertise of Ciner Group, theworld’s largest natural soda ash producer, effective as of the end of day on December 31, 2020, Sisecam Chemicals exited ANSAC (the “ANSAC termination date”)and ANSAC has no longer been an affiliate since January 1, 2021. Through in part the Partnership’s affiliates, the Company has amongst other things: (i) obtainedits own international customer sales arrangements for 2021 and 2022, (ii) obtained third-party export port services, and (iii) chartered and executed its owninternational product delivery. For the year ended December 31, 2022, the total logistic services, which are included in cost of products sold-affiliates wereapproximately $15,136 and for year ended December 31, 2021, the total logistic services which are included in cost of products sold-affiliates was $3,468. For the yearended December 31, 2020 there were no costs of products sold affiliates. Although ANSAC has historically been our largest customer, the impact of Sisecam Chemicals' exit from ANSAC on our net sales, net income and liquidity waslimited. With a low-cost position and improved access to international customers and control over placement of its sales in the international marketplace andlogistics, we have adequately replaced these net sales made under the former agreement with ANSAC. Since January 1, 2021 and 2022, Sisecam Chemicals hasmanaged the Company’s sales and marketing activities for exports with the ANSAC exit being complete. Sisecam Chemicals leveraged the distributor networkestablished by the Ciner Group in 2021 and continues to evaluate the distribution network and independent third-party distribution partners to optimize our reachinto each market. Selling, general and administrative expenses also include amounts charged to the Company by its affiliates principally consisting of salaries, benefits, officesupplies, professional fees, travel, rent and other costs of certain assets used by the Company. On October 23, 2015, Sisecam LP entered into a Services Agreement(the “Services Agreement”) with the general partner and Sisecam Chemicals. Pursuant to the Services Agreement, Sisecam Chemicals has agreed to provide SisecamLP with certain corporate, selling, marketing, and general and administrative services, in return for which Sisecam LP has agreed to pay Sisecam Chemicals an annualmanagement fee and reimburse Sisecam Chemicals for certain third-party costs incurred in connection with providing such services. In addition, under the limitedliability company agreement governing Sisecam Wyoming, Sisecam Wyoming reimburses Sisecam LP for employees who operate Sisecam LP's assets and forsupport provided to Sisecam Wyoming. These transactions do not necessarily represent arm's length transactions and may not represent all costs if SisecamWyoming operated on a standalone basis. The total selling, general and administrative costs charged to the Company by affiliates for the years ended December 31, 2022, 2021 and 2020 were as follows: 2022 2021 2020 Sisecam Chemicals $19,016 $16,494 $15,659 ANSAC (1) N/A N/A 1,362 Sisecam LP 245 141 377 Total selling, general and administrative expenses - affiliates $19,261 $16,635 $17,398 (1) ANSAC allocates its expenses to its members using a pro rata calculation based on sales. 27 Net sales to affiliates for the years ended December 31, 2022, 2021 and 2020 were as follows: 2022 2021 2020 ANSAC N/A N/A $177,891 Total N/A N/A $177,891 As of December 31, 2022 and 2021, the Company had due from/to with affiliates as follows: 2022 2021 Accounts receivable -affiliates Due to affiliates Accounts receivable -affiliates Due to affiliates Sisecam Chemicals $53,862 $3,408 $49,285 $1,996 Other 62 2,653 232 132 Total $53,924 $6,061 $49,517 $2,128 14. SEGMENT REPORTING Our operations are similar in geography, nature of products we provide and type of customers we serve. As the Company earns substantially all of its revenuesthrough the sale of soda ash mined at a single location, we have concluded that we have one operating segment for reporting purposes. The net sales by geographic area for the years ended December 31, 2022, 2021 and 2020 were as follows: 2022 2021 2020 Domestic $304,994 $276,778 $208,838 International 415,126 263,361 183,393 Total net sales $720,120 $540,139 $392,231 We have two major international customers which individually account for over 10% of net sales for the years ended December 31, 2022 and 2021 and had onemajor international customer which accounted for over 10% of net sales for the year ended December 31, 2020. Revenues from these major customers wereapproximately $188,162 for the year ended December 31, 2022, $173,000 for the year ended December 31, 2021, and $177,891 for the year ended December 31,2020. The two major international customers in 2022 had a combined accounts receivable balance of $45,917 at December 31, 2022. The two major internationalcustomers in 2021 had a combined accounts receivable balance of $44,709 at December 31, 2021. 15. SUBSEQUENT EVENTS Cash Distribution On February 9, 2023, the members of the board of managers of Sisecam Wyoming, approved a cash distribution to the members of Sisecam Wyoming in theaggregate amount of $22,000. This distribution was paid on February 20, 2023. ****** 28Unitholder Information Partnership Headquarters Website 1415 Louisiana Street Suite 3325 Houston, TX 77002 713-751-7507 Regional Offices Mineral Rights 5260 Irwin Road Huntington, WV 25705 Investor Relations Tiffany Sammis 1415 Louisiana Street Suite 3325 Houston, TX 77002 713-751-7515 Email: info@nrplp.com Stock Exchange Our units are listed on the New York Stock Exchange under the symbol NRP. Independent Auditors Ernst & Young LLP 5 Houston Center 1401 McKinney, Suite 2400 Houston, TX 77001-2007 Transfer Agent and Registrar American Stock Transfer and Trust Company Client Operations 6201 15th Avenue Brooklyn, NY 11219 Website: www.astfinancial.com Email:help@astfinancial.com 800-937-5449 www.nrplp.com Information regarding Natural Resource Partners L.P. is located on the partnership’s website. On the site is operational and financial information as well as all SEC filings and our corporate governance documents, including our Code of Business Conduct and Ethics, our Corporate Governance Guidelines and Board of Directors’ Audit Committee Charter. Requests for copies of the annual report or other data may be made through the website or by contacting Investor Relations. These requests will be provided free of charge. Contact NRP Board We have established procedures for contacting the non-management members of the NRP Board of Directors. To communicate any concerns or issues to the Board of Directors, please direct any correspondence to: Chairman of the CNG Committee NRP Board of Directors 1415 Louisiana Street, Suite 3325 Houston, TX 77002 888-252-2396 Schedule K-1 Unitholders receive Schedule K-1 packages that summarize their allocated share of the partnership’s reportable tax items for the calendar year. Generally, these K-1s are available on NRP’s website no later than mid-March. Unitholders should refer questions regarding their Schedule K-1 to the following: Natural Resource Partners L.P. Tax Package Support P.O. Box 799060 Dallas, TX 75379-9060 Fax: 1-866-554-3842 Toll Free: 1-888-334-7102 Forward-Looking Statements Statements included in this annual report may constitute forward-looking statements. In addition, we and our representatives may from time to time make other oral or written statements which are also forward-looking statements. Such forward-looking statements include, among other things, statements regarding: the effects of the global COVID-19 pandemic; future distributions on our common and preferred units; our business strategy; our liquidity and access to capital and financing sources; our financial strategy; prices of and demand for coal, trona and soda ash, and other natural resources; estimated revenues, expenses and results of operations; projected production levels by our lessees; Sisecam Wyoming LLC’s ("Sisecam Wyoming's"), formerly known as Ciner Wyoming, trona mining and soda ash refinery operations; distributions from our soda ash joint venture; the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us, and of scheduled or potential regulatory or legal changes; and global and U.S. economic conditions. These forward-looking statements speak only as of the date hereof and are made based upon our current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should not put undue reliance on any forward-looking statements. See "Item 1A. Risk Factors" in this Annual Report on Form 10-K for important factors that could cause our actual results of operations or our actual financial condition to differ. 63615natD1R2_Cov.indd 3 63615natD1R2_Cov.indd 3 4/17/23 5:18 PM 4/17/23 5:18 PM Natural Resource Partners L.P.1415 Louisiana Street, Suite 3325Houston, Texas 77002www.nrplp.com63615natD1R2_Cov.indd 463615natD1R2_Cov.indd 44/17/23 5:18 PM4/17/23 5:18 PM

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